Automated system and method for use in well control

ABSTRACT

An automated system for use in well control comprises a controller configured to receive an input signal indicative of a fluid flow rate or fluid volumetric rate from a wellbore. The controller is configured to determine from the input signal whether the fluid flow rate or fluid volumetric rate exceeds a preselected threshold indicative of a fluid influx condition in the wellbore system. On determining that the fluid flow rate or fluid volumetric rate exceeds the preselected threshold, the controller is configured to automatically output one or more command signals initiating an initial well control protocol.

FIELD

This relates to an automated system and method for use in well control.More particularly, this relates to an automated system and method fordetecting the presence of a fluid influx condition in a wellbore andautomatically initiating an initial well control protocol.

BACKGROUND

Well control techniques are used in oil and gas operations such asdrilling, tripping, well workover, and well completion in order tomaintain fluid pressure at certain points in a wellbore above aformation pressure and thereby prevent influx of formation fluids intothe wellbore. This is known in the industry as “overbalanced”differential pressure.

With the pumps on and fluid circulating, a combination of hydrostaticpressure, dynamic friction pressure and surface pressure may combine tomaintain an overbalanced differential pressure in a wellbore. In theevent that an “underbalanced” differential pressure comes to exist inthe wellbore, that is where fluid pressure at certain points in thewellbore is less than the formation pressure, formation fluids may flowinto the wellbore in what is known in the industry as fluid influx.

The fluid influx will continue until the fluid pressure in the wellboreis increased by fluid flow from the formation to the wellbore. This typeof fluid influx may be referred to as a “self-sustained” influx. Theself-sustained influx should be stopped as quickly as possible and theunwanted fluid safely removed from the wellbore before continuing withoil and gas operations. Notably, a self-sustained influx is oftengenerally characterised in the industry as a “kick” or “influx” alongwith other non-self-sustained influxes (e.g. a swabbed influx) requiringdifferent remedial action. As explained below, this exacerbates problemswith accurately identifying a self-sustained influx withopen-to-atmosphere annulus fluid systems.

Upon suspicion or sign of a self-sustained influx, a driller may attemptto confirm whether such an event is indeed occurring before initiatingwell control techniques by carrying out a flow check procedure. Atypical flow check procedure involves positioning the drill bit at asuitable position above the bottom of the wellbore/borehole, stoppingrotation of the drill string, and then stopping the mud pumps. Thedriller then checks to see if there is any flow returning from the wellannulus (i.e., whether the well is “flowing”) with the pumps off. If thewell is flowing, with the pumps off, the driller may conclude that sometype of influx is entering the wellbore. Conventional flow checkprocedures today are performed entirely with the BOP open, i.e., with anopen-to-atmosphere annulus fluid system.

There are a number of challenges with conventional methods.

Very often, using an open-to-atmosphere system is inadequate for the rigcrew to accurately and quickly come to a conclusion as to whether aself-sustained influx is indeed happening or not due to a variety ofother benign causes for such a perceived influx. For example, onfloating installations, relatively small yet significant self-sustainedinfluxes may be difficult to observe because the conventional flow checkprocedure may be affected by installation motion and heave effects.

Also, flow check procedures take time that is often prescribed byprocedure (for example requiring a minimum of 10, 15, or 30 minutes).Drillers may hesitate to risk stopping drilling operations for suchperiods until and/or unless clear justification exists.

Moreover, a driller who has had the experience of stopping to perform aflow check procedure only to find no self-sustained influx existed maybe less likely to quickly do so again, even if new circumstances justifyit, if the earlier flow check resulted in delay, costs or operationalproblems that could otherwise have been avoided by not performing theflow check procedure.

SUMMARY

According to a first aspect, there is provided an automated system foruse in well control, the system comprising:

a controller configured to receive an input signal indicative of a fluidflow rate or fluid volumetric rate from a wellbore, the controllerconfigured to determine from said input signal whether the fluid flowrate or fluid volumetric rate exceeds a preselected threshold indicativeof a fluid influx condition in the wellbore system,

wherein, on determining that said fluid flow rate or fluid volumetricrate exceeds said preselected threshold, the controller is configured toautomatically output one or more command signals initiating an initialwell control protocol.

Beneficially, the system permits an initial well control protocol to beactioned based on preselected criteria, and without the requirement foran operative, such as the driller, to decide and/or action the requiredinitial well control operations. The system is particularly, althoughnot exclusively, beneficial in open-to-atmosphere wellbore systems whereit is difficult or impossible using conventional techniques for thedriller to accurately and quickly conclude whether a self-sustainedinflux is occurring.

The system is capable of reducing the size of an influx compared toconventional open-to-atmosphere techniques, which in turn reduces therisk of fracture and potential underground blow out due to lowerwellbore pressures, particularly but not exclusively at the open shoe ofthe wellbore.

The system also has the benefit of reducing delay, costs and/oroperational problems that may otherwise occur where a well controloperation is initiated unnecessarily, while also obviating the risk thatthe operative will then subsequently not act promptly when an influxcondition does occur.

Moreover, the system permits the initial well control protocol to beinitiated based on a single parameter, i.e. fluid flow rate or fluidvolumetric rate from the wellbore. The system may be configured tointerface with a variety of well control systems. However, the abilityto initiate and/or perform the initial well control protocol based on asingle parameter provides not only a simple and effective system for usein well control operations, but one which does not rely on interfacingwith a variety of systems which are typically provided by differentsuppliers and which may rely on proprietary systems. The system may thusbe readily retrofitted to existing wellbore infrastructure, withoutsignificantly impacting on existing systems and/or infrastructure.

The system's ability to detect and automatically initiate the initialwell control protocol without manual intervention also facilitates moreefficient well operations and/or production. For example, conventionaldrilling methodologies teach that, where an influx or potential influxevent occurs, the well-plan may have to be modified with an additionalstring of casing thereby increasing the cost of drilling the wellboreand/or reducing future production capacity. The present system permitsthe operator to work within smaller tolerances and thus require fewerchanges to the well-plan, reducing the capital expenditure in drillingthe wellbore and utilising larger casing strings to greater depths, andthus increasing production capacity.

As described above, the controller is configured to determine from theinput signal whether the fluid flow rate or fluid volumetric rateexceeds a preselected threshold indicative of a fluid influx conditionin the wellbore, and on determining that said received fluid flow rateor fluid volumetric rate exceeds said preselected threshold output oneor more command signals initiating an initial well control protocol.

The threshold may be set during set up of the system. For example, thethreshold may be set by the operative and/or the operator company duringset up of the system. Beneficially, this permits the threshold to betuned/adjusted according to the driller's and/or operator's preferences,experience, environment; given well-plan or the like; but within a rangebounded by appropriate factors of safety.

The initial well control protocol may comprise a well shut-in protocol.

The initial well control protocol may comprise one or more preselectedwell control operations.

The one or more preselected well control operations may be set duringset up of the system. For example, the one or more preselected wellcontrol operations may be set by the operative and/or the operatorcompany during set up of the system. Beneficially, this permits the oneor more preselected well control operations to be tuned adjustedaccording to the driller's and/or operator's preferences, experience,environment; given well-plan or the like; but within a range bounded byappropriate factors of safety.

In particular embodiments, the initial well control protocol maycomprise a plurality of well control operations.

The system may be configured for coupling to, to communicate with or maybe operatively associated with components of an oil and/or gasinstallation (“the installation”).

The system may be configured for coupling to, to communicate with or maybe operatively associated with a drawworks of the installation.

More particularly, but not exclusively, the system may be configured forcoupling to, to communicate with, or may be operatively associated witha controller of the drawworks of the installation.

The initial well control protocol may comprise a command signal to thedrawworks to raise the drill string off the bottom of the wellbore.

The distance that the drawworks is raised may be set by the operative,e.g. driller, during set up of the system, but will occur automaticallyonce the control system has been enabled. Beneficially, this prevents orat least reduces the likelihood that the drawworks could be raised to aposition at which a tubing connection is disposed adjacent to theclosure mechanism of the blow out preventer.

The system may be configured for coupling to, to communicate with or maybe operatively associated with a top drive of the installation.

More particularly, but not exclusively, the system may be configured forcoupling to, to communicate with or may be operatively associated with acontroller of the top drive.

The initial well control protocol may comprise a command signal to thetop drive to stop rotation of the top drive.

The system may be configured for coupling to, to communicate with or maybe operatively associated with one or more mud pumps of theinstallation.

More particularly, but not exclusively, the system may be configured forcoupling to, to communicate with or may be operatively associated with acontroller of the mud pumps.

The initial well control protocol may comprise a command signal to themud pumps to stop the mud pumps, or a preselected subset of the mudpumps.

The initial well control process may comprise monitoring the fluid flowrate or fluid volumetric rate over a preset test period.

The preset test period may be 1 second. However, it will be recognisedthat the preset test period may be any suitable time period.

The preset test period may be preselected by the operative, e.g.driller, during set up of the system.

The system may be configured so that if, after the pre-set test periodhas elapsed, the fluid flow rate or fluid volumetric rate remains abovethe preselected threshold the system will determine that an influxcondition is present in the wellbore.

Alternatively or additionally, the initial well control process maycomprise periodically checking the fluid flow rate or fluid volumetricrate at any point in the well control process.

The initial well control process may comprise checking the fluid flowrate or fluid volumetric rate after a pre-set time delay.

Alternatively or additionally, the system may be configured so that, onreceiving confirmation that the mud pumps of the installation havestopped, and a further time period has elapsed, in the event that fluidflow has not reduced to a negligible level the system will determinethat an influx condition is present in the wellbore. The pre-set timeperiod may be adjustable by the operative, e.g. driller, during set upof the system, but will occur automatically once the control system hasbeen enabled.

The further time period may be adjustable by the operative, e.g.driller, during set up of the system, but will occur automatically oncethe control system has been enabled. The system may be configured forcoupling to, to communicate with or may be operatively associated with ablow out preventer (the “BOP”) of the installation.

More particularly, but not exclusively, the system may be configured forcoupling to, to communicate with or may be operatively associated with acontroller of the BOP.

The initial well control protocol may comprise a command signal to theBOP to close the BOP, and thus shut-in the wellbore.

The system may be configured to action a further well control protocol.The further well control protocol may comprise or take the form ofinflux circulation operation.

The further well control protocol may comprise or take the form of awell kill operation, that is placing a column of heavy fluid into awellbore in order to prevent the flow of reservoir fluids.

The system may be configured for coupling to, to communicate with or maybe operatively associated with at least one of a choke panel, chokemanifold and/or mud pump of the installation.

Alternatively, the further well control protocol may comprise or takethe form of a fluid pumping operation.

Conventionally, a leak off test (LOT) procedure is undertaken during thewellbore construction process after each new string of casing has beensecured in the wellbore. This establishes the strength of the formationat the casing shoe. During the wellbore construction process, theMaximum Allowable Annulus Surface Pressure (MAASP), derived from theLOT, must not be exceeded, otherwise an underground blowout may beinitiated. This may lead to a breach to surface and must be avoided.

The fluid pumping operation may comprise pumping fluid, in particulardrilling mud, into the shut-in wellbore before or after, for example butnot exclusively immediately after, the wellbore has been shut.

The fluid pumping operation may comprise pumping mud into the wellboreuntil a pre-determined pressure is reached.

In particular embodiments, the pre-determined pressure is less thanMAASP or shoe fracture pressure, thereby ensuring that an undergroundblowout does not occur.

The pre-determined pressure may be equal to or greater than theformation pressure that caused the influx.

Beneficially, the fluid pumping operation reduces or minimises thevolume of the influx. Minimising the influx volume has severaladvantages. For example, a reduced influx volume may result in lowerpressure being exerted on the wellbore and the rig equipment. There isalso a reduced risk of getting stuck and other hole problems. Moreoptions to kill the well become available, particularly using thebull-heading technique to displace the influx back into the donorformation. The system assures the operator that the influx volume wouldbe significantly reduced, in particular but not exclusively to a maximumof five barrels of influx.

As described above, the system may be configured for coupling to, tocommunicate with or may be operatively associated with a choke paneland/or choke manifold of the installation.

As described above, the system comprises a controller configured toreceive an input signal indicative of a fluid flow rate or fluidvolumetric rate from a wellbore.

The input signal may take the form of fluid flow data from the wellbore,in particular real time fluid flow data or fluid volumetric rate fromthe wellbore. In particular, the input signal may comprise drillingfluid or mud flow or volume data.

The controller may be configured to additionally receive one or moreinput signal in the form of: fluid volume data; fluid volumetricdisplacement data; pressure data; depth data, e.g. indicative of therate of penetration of the drillstring; weight data, e.g. weight of thedrillstring; gas detection data; data indicative of the gas percentagein the drilling fluid; drilling fluid property data (e.g. indicative offluid weight, yield point and/or plastic viscosity); equipment speeddata; equipment condition data, e.g. indicative of valve position and/orchoke position; movement data regarding the installation i.e. indicativeof heave, sway, surge, roll, pitch and yaw; environmental data e.g. windspeed and/or direction; tidal data; GPS and/or other positioning systemdata; data from another source.

Alternatively or additionally, the controller may be configured toreceive one or more input signal in the form of managed pressuredrilling (MPD) system data.

Alternatively or additionally, the controller may be configured toreceive one or more input signal in the form of early kick detectionsystem (EKDS) data.

Alternatively or additionally, the controller may be configured toreceive one or more input signal in the form of a manual confirmationinput, e.g. from the operative. Alternatively or additionally, thecontroller may be configured to receive one or more input signal in theform of well control procedure data, e.g. a data library of well controlprocedures from one or more operator and/or leak-off test data (e.g.pressure & depth data), or other data source.

The system may comprise, may be coupled to or may communicate with, asensor arrangement.

The system may communicate with the sensor arrangement via a wiredcommunication arrangement and/or communication protocol.

Alternatively or additionally, the system may communicate with thesensor arrangement via a wireless communication arrangement and/orcommunication protocol, in particular but not exclusively a radiofrequency (RF) communication arrangement.

The sensor arrangement may comprise one or more sensor configured todetect the fluid flow rate from the wellbore.

The sensor arrangement may comprise or take the form of a fluid flowsensor.

For example, the sensor arrangement may comprise a fluid flow sensor of,or operatively associated with, the mud flow system.

The system may comprise, may be coupled to or may communicate with, asingle fluid flow sensor or a plurality of fluid flow sensors.

The sensor arrangement may be located on, disposed in, or operativelyassociated with a fluid return line of the wellbore.

The sensor arrangement may be located on a return line from theinstallation's flow control device manifold while the sensors measuredrilling parameters elsewhere in the system.

Alternatively or additionally, the sensor arrangement may comprise ortake the form of a mass flowmeter, e.g. a Coriolis mass flowmeter.

The mass flowmeter may be disposed either upstream or downstream fromthe sensor arrangement in the return line.

Alternatively or additionally, the sensor arrangement may be configuredto detect the fluid volumetric rate.

The sensor arrangement may comprise one or more sensors configured todetect fluid volume.

Alternatively or additionally, the sensor arrangement may comprise oneor more of: a sensor configured to measure fluid volumetricdisplacement; a pressure sensor; a depth sensor configured to measurethe rate of penetration of the drillstring; a weight sensor configuredto measure weight of the drillstring; a gas detection sensor configuredto detect the presence and/or percentage of gas in the drilling fluid;one or more sensors configured to measure fluid weight, yield pointand/or plastic viscosity; a speed sensor configured to measure equipmentspeed; a condition sensor configured to measure equipment condition,e.g. configured to measure a valve position and/or choke position; amovement sensor configured to measure heave, sway, surge, roll, pitchand yaw of the installation; a wind speed and/or direction sensorconfigured to wind speed and/or direction.

The sensor arrangement may comprise one or more sensor of, oroperatively associated with, a trip tank of the installation.

The sensor arrangement may comprise one or more sensor of, oroperatively associated with, a pit volume totalizer of the installation.

The system may be configured for coupling to, to communicate with or maybe operatively associated with rig data system of the installation.

The system may comprise, may be coupled to, or operatively associatedwith a human machine interface (HMI) arrangement.

The HMI arrangement may be disposed on the installation, e.g. drillingrig, platform or the like. In particular, but not exclusively, the HMIarrangement may be disposed on the driller's console.

Alternatively, the HMI arrangement may be disposed at a remote location,such as another drilling rig or platform, onshore facility or othersuitable location.

The system may be configured to receive commands through the HMIarrangement.

For example, the operative may set up and/or enable the system via theHMI arrangement.

As described above, the controller is configured to output a commandsignal to well control infrastructure initiating an initial well controlprotocol.

The system may comprise a communication arrangement configured tocommunicate said command signal to the well control infrastructure.

The communication arrangement may comprise a wired communicationarrangement.

The wired communication arrangement may comprise an optical fibrearrangement, electrical cable or the like.

Alternatively or additionally, the communication arrangement maycomprise a wireless communication arrangement, such as a radio frequency(RF) communication arrangement or the like.

The communication arrangement may be configured to communicate to theoperative, e.g. via the HMI arrangement, that the initial well controlprotocol and/or the further well control protocol have been initiated.

The communication arrangement may communicate the actions carried out aspart of the initial well control protocol and/or the further wellcontrol protocol to the operative, e.g. via the HMI arrangement.Beneficially, this provides the operative, e.g. driller, with a visualstatus indicator of the actions being carried out automatically by thesystem and/or permits the operative to verify those actions as they arecarried out.

The method may comprise outputting an output signal to the operative,e.g. driller. In use, the output signal indicates to the operative, e.g.driller, than an increase in flow rate has been detected and that theinitial well control process has been initiated; the operative is notrequired to take action in response to the output signal.

The output signal may comprise an alarm signal.

The output signal may comprise an audible alarm signal.

The output signal may comprise a visual alarm signal.

As described above, the system comprises a controller configured toreceive the input signal indicative of a fluid flow rate from awellbore, the controller configured to determine from said input signalwhether the fluid flow rate exceeds a preselected threshold fluid flowrate indicative of a fluid influx condition in the wellbore system.

The controller may comprise a Programmable Logic Controller (PLC).

The controller may comprise a plurality of PLCs.

In particular embodiments, the controller may comprise two PLCs.

The PLCs may be synchronised.

The PLCs may be linked via a wired communication arrangement, such as anoptical fibre.

The controller may comprise one or more CPU.

The controller may comprise a memory unit.

The controller may comprise, or may be coupled to, a power supplymodule.

The power supply module may operate on a DC supply, e.g. a 24V DCsupply.

The system may comprise an input/output module.

The input/output module may be configured to provide communicationbetween the controller and the components of the installation.

The input/output module may be configured to provide communicationbetween the controller and the sensor arrangement and/or data source.

The input/output module and the controller may communicate via a wiredor wireless communications arrangement and/or protocol. For example, theinput/output module and the controller may communicate via a ProcessField Bus (Profibus) interface.

The system may comprise, or may be coupled to, an Industrial PersonalComputer (IPC).

The IPC may be operable to run the software for the HMI arrangement.

The system may comprise network switch, e.g. an Ethernet switch, or thelike.

The network switch, e.g. Ethernet switch, may be configured tofacilitate communication with multiple devices of the installationsimultaneously.

The system may comprise an uninterruptable power supply (UPS) module.

The system may comprise a battery.

In use, the UPS module and/or the battery may provide back-up power tothe components of the system in the event of power failure.

The system may comprise an Intrinsically Safe (IS) barrier unit.

The IS barrier unit may be configured to convert the 24V DC power supplyinto one that is safe for use in a hazardous area by virtue of theconverted supply not being powerful enough to cause an ignition source,spark or the like.

The system may comprise an AC/DC converter unit.

The AC/DC converter unit may be configured to converting a 240V ACsupply to a 24V DC supply for the controller and/or other component ofthe system.

The components of the control system may communicate via a wired orwireless, in particular but not exclusively radio frequency,communications arrangement and/or protocol.

According to a second aspect, there is provided an offshore or onshoreoil and gas installation comprising the system of the first aspect.

According to a third aspect, there is provided an automated method foruse in well control, the method comprising:

receiving a signal indicative of a fluid flow rate or fluid volumetricrate from a wellbore;

determining from said signal whether the fluid flow rate or fluidvolumetric rate exceeds a preselected threshold fluid flow rate,

wherein, on determining that said received fluid flow rate or fluidvolumetric rate exceeds said preselected threshold fluid flow rate, themethod comprises automatically initiating an initial well controloperation.

Beneficially, the method permits an initial well control protocol to beactioned based on preselected criteria, and without the requirement forthe operative, such as the driller or other rig crew, to action therequired initial well control operations. The method is particularly,although not exclusively, beneficial in open-to-atmosphere wellboresystems where it is difficult or impossible using conventionaltechniques for the driller or rig crew to accurately and quicklyconclude whether a self-sustained influx is occurring, therebyincreasing the safety and/or reducing the risk of damage to the wellboreinfrastructure and/or formation due to formation fracture or blow out.

The method also has the benefit of reducing delay, costs and/oroperational problems that may otherwise occur where a well controloperation is initiated unnecessarily, while also obviating the risk thatthe operative will then subsequently not act promptly when an influxcondition does occur.

Moreover, the method permits the initial well control protocol to beinitiated based on a single parameter, i.e. fluid flow rate from thewellbore. The ability to initiate and/or perform the initial wellcontrol protocol based on a single parameter provides not only a simpleand effective system for use in well control operations, but one whichdoes not rely on interfacing with a variety of systems which aretypically provided by different suppliers and which may rely onproprietary systems. The method may thus be readily employed usingexisting wellbore infrastructure, without significantly impacting onexisting systems and/or infrastructure.

The method may comprise actioning a further well control protocol.

The further well control protocol may comprise the control systemassuming control of the well control and/or drilling equipment of theinstallation.

The further well control protocol may comprise or take the form ofinflux circulation operation.

The further well control protocol may comprise or take the form of awell kill operation, that is placing a column of heavy fluid into awellbore in order to prevent the flow of reservoir fluids,

Alternatively, the further well control protocol may comprise or takethe form of a fluid pumping operation.

The fluid pumping operation may comprise pumping fluid, in particulardrilling mud, into the shut-in wellbore immediately after the wellborehas been shut.

The fluid pumping operation may comprise pumping drilling fluid/mud intothe wellbore until a pre-determined pressure is reached.

In particular embodiments, the pre-determined pressure is less thanMAASP or shoe fracture pressure, thereby ensuring that an undergroundblowout does not occur.

The pre-determined pressure may be equal to or greater than theformation pressure that caused the influx.

The method may comprise the preliminary step of setting up and/orenabling the system.

The system may be set up and/or enabled by the operative, e.g. driller,via the human machine interface (HMI) arrangement.

The step of setting up the system may comprise calibrating the drawworksspace out configuration by calibrating set points for movement of thedrawworks.

Beneficially, this ensures that the BOP does not close on a connection.The calibration may be achieved by logging set points for upper, mid andlower positions in the system.

For example, the operative, e.g. driller, may raise the drawworks to afirst “space out position” with the tool joint clear of the BOP, thenlog this position as an “Upper Set

Point” via the HMI arrangement. The operative, e.g. driller, may thenlower the drawworks to a second “space out position” with the tool jointclear of the BOP, then log this position as a “Mid Set Point” via theHMI arrangement. Finally, the operative, e.g. driller, may then lowerthe drawworks to a third “space out position” with the tool joint clearof the BOP, then log this position as a “Lower Set Point” via the HMIarrangement

It will be recognised that any number of positions may be logged, asappropriate.

The positions may be recorded and displayed on the HMI.

The method may comprise the preliminary step of carrying out drilling ortripping operations.

In use, the operative, e.g. driller, is able to control the drillingequipment and begins drilling operations as if the automated system wasnot there.

As described above, the method involves determining whether or not thefluid flow rate exceeds the preselected threshold fluid flow rate.

The threshold fluid flow rate may be adapted by the operative, e.g. bythe driller.

The ability to adapt the threshold fluid flow rate provides a degree offlexibility within acceptable safety margins while ensuring that therequired initial well control operation is carried out automaticallywhen required.

As described above, the method comprises receiving a signal indicativeof a flow rate from a wellbore.

The signal may be indicative of an increased fluid flow rate from thewellbore.

The signal indicative of a flow rate from the wellbore may be receivedfrom a rig data system or the like.

Alternatively or additionally, the signal indicative of a flow rate fromthe wellbore may be received from instrumentation. This may be the case,for example, on older installations that do not have a rig data system.

As described above, the method comprises: receiving a signal indicativeof a fluid flow rate or fluid volumetric rate from a wellbore;determining from said signal whether the fluid flow rate or fluidvolumetric rate exceeds a preselected threshold fluid flow rate,wherein, on determining that said received fluid flow rate or fluidvolumetric rate exceeds said preselected threshold fluid flow rate, themethod comprises automatically initiating an initial well controloperation.

The method may further comprise one or more steps in the form of tests.The method may comprise one or more of the steps of checking that thecomplete system operates; and establishing a tolerance window. The oneor more steps of checking that the complete system operates; andestablishing a tolerance window may be performed prior to establishingmud pump (MP1) and/or mud pump (MP2) flowrates for future tests.

The method may comprise one or more of the steps of:

-   -   i) finalising a flowrate for MP1 to be used for all future        tests;    -   ii) finalising a Flowrate for MP2 that triggers a shut-in        procedure initiated from Flowcheck 1;    -   iii) Finalising a Flowrate for MP2 that triggers a shut-in        procedure initiated from Flowcheck 2;    -   iv) Finalising a Flowrate for MP2 that does not trigger a        shut-in procedure from either Flowcheck;    -   v) Finalising Time Delays, No Flow Limit, Flowrate Threshold        Limit from Test 1.

The method may comprise the step of checking that the system willshut-in using each of the 3 space-out positions.

The method may comprise the step of comparing the time taken to manuallyshut-in the well compared with the system shutting in one or more of thepositions of i). Flowcheck 1 and ii). Flowcheck 2.

The method may comprise the step of assessing the operation of thesystem to assess whether all equipment is unselected. The method maycomprise a further step of identifying an influx.

The method may comprise the step of assessing the operation of thesystem to assess whether the top drive is unselected. The method maycomprise a further step of identifying an influx.

The method may comprise the step of assessing the operation of thesystem to assess whether one or more mud pumps are unselected.

The method may comprise a further step of identifying an influx.

The method may comprise the step of assessing the operation of thesystem to assess whether the drawworks are unselected on the HMIarrangement.

The method may comprise a further step of identifying an influx.

The method may comprise the step of assessing the operation of thesystem to assess whether a tool joint is in a space-out tolerance windowwhen an influx is identified.

The mud pump flow rate may be adjusted and/or varied during the drillingprocess, e.g. while drilling. The method of adjusting and/or varying themud pump flow rate may comprise the steps of:

(i) switching the system off;

(ii) adjusting mud pumps;

(iii) re-setting the base flow rate;

(iv) switching the system on.

Alternatively, the mud pumps may be adjusted whilst the system isswitched on. The resulting effects may be noted and/or recorded.

Slow Circulating Rates (SCRs) may be performed during the drillingprocess, e.g. while drilling.

The method of performing SCRs during the drilling process may comprisethe steps of:

(i) switching the system off;

(ii) performing SCRs; and

(iii) switching the system on;

Alternatively, the drilling operator may perform the SCRs with thesystem switched on.

The top drive may be switched off and/or deactivated during the drillingprocess, e.g. while drilling. The method of switching off and/ordeactivating the top drive during the drilling process may comprise thesteps of:

(i) switch the system off;

(ii) switch the top drive off; and

(iii) switch the system on.

This test may assess the effect of switching off or attempting to switchoff the top drive on the HMI whilst the system is switched on.

The method may assess the effect that the installation experiencing anEmergency Shut Down (ESD) has on the system while the system is switchedon.

The method may assess whether the steady circulating flowrate (of MP1)is sufficiently disturbed by the drill-string being run in hole (RIH)such that flowrate transients are created that will cause the flowrateto increase to beyond the set Flowrate Threshold Limit.

The method may assess if the steady circulating flowrate (of MP1) isdisturbed sufficiently by the drill-string being pulled out of hole(POOH) such that flowrate transients are created that may cause theflowrate to increase to beyond the set flowrate threshold limit.

The system may be configured for operation with an oil and/or gasinstallation having a rig control system or may be used with aconventional/traditional installation, i.e. without a rig controlsystem.

The system may be connected to at least one of the installation, rigcontrol unit and master BOP control panel via suitable connectionarrangement. The suitable connections arrangement may comprise a wiredconnection arrangement, or may comprise a wireless communicationarrangement.

Data from the system may be transferred between, e.g. to and/or from therig equipment control units and/or master BOP control panel.

Various methods for adapting the system to a traditional installationwithout a rig control system may be employed.

According to a first method, connections may be hardwired or data fromthe system may be transferred to the installation's equipment controlunits in the silicon controller rectifier room and master BOP controlpanel. The system may be connected to at least one of the top drive, mudpumps, drawworks and BOP via the suitable connection arrangement.

Alternatively or additionally, at least one of the top drive, mud pumps,drawworks and BOP may be connected, e.g. wired from the control systemto a remote panel which may be located at and/or on the rig floor. Theremote panel may be connected, e.g. wired to relays in the rig'sdrillers' panel. The remote panel may be suitable for control of atleast one of the top drive, mud pumps and drawworks equipment.

The BOP connection may be wired from the remote panel to relays. Theremote panel relays may be located in one or more of the systemenclosure; in the installation's BOP remote control panel; or to otherBOP control panel.

Alternatively or additionally, the relays may be disposed in the remotepanel or other separate enclosure which may be disposed on the rigfloor.

The relays may be connected, e.g. wired to at least one of the rig'sdrillers' panel and the installation's BOP Remote control panel.

The system may comprise, may be configured for coupling to, oroperatively associated with, a brake system.

The brake system may comprise a manual brake.

The brake system may be operated via a connection from one or more ofthe remote panel; pneumatic controls to the installation's brake, orrelay interface to electrical brake controls.

The brake system may be, or take the form of a band brake or disc brakeor the like.

The brake system may comprise a travelling equipment protectionarrangement.

The travelling equipment protection arrangement may comprise or take theform of an automated or partially automated system.

The travelling equipment protection arrangement may comprise anelectronic travelling equipment protection arrangement.

The brake system may comprise, or may be configured for coupling to, aCrown-o-matic and/or Crown-saver system, or the like.

The drawworks height may be controlled via a connection between, e.g. toand/or from the remote panel and a drawworks encoder.

The drawworks height may be controlled via data connections to a riginstrumentation data logging system.

The system may be connected to a installation flowrate sensor. Theflowrate sensor may be of the paddle, J-tube, Coriolis meter type orother suitable flow metering device.

The system may be connected to one or more of mud pit level or trip tanklevel sensors.

The system may comprise, may be configured for connection to or may beoperatively associated with a managed pressure drilling system of theinstallation.

The system may comprise an early kick detection system.

The system may be configured for connection to and/or operativelyassociated with an early kick detection system of the installation.

According to a further aspect, there is provided an automated system foruse in well control.

The system may comprise a controller configured to receive an inputsignal. The input signal may be indicative of a fluid influx conditionin the wellbore system.

The controller may be configured to automatically output one or morecommand signals initiating an initial well control protocol.

The controller may be configured to receive an input signal indicativeof a fluid flow rate or fluid volumetric rate from a wellbore.

The input signal may take the form of fluid flow data from the wellbore,in particular real time fluid flow data or fluid volumetric rate fromthe wellbore. In particular, the input signal may comprise drillingfluid or mud flow or volume data.

The controller may additionally receive one or more input signal in theform of: fluid volume data; fluid volumetric displacement data; pressuredata; depth data, e.g.

indicative of the rate of penetration of the drillstring; weight data,e.g. weight of the drillstring; gas detection data; data indicative ofthe gas percentage in the drilling fluid;

drilling fluid property data (e.g. indicative of fluid weight, yieldpoint and/or plastic viscosity); equipment speed data; equipmentcondition data, e.g. indicative of valve position and/or choke position;movement data regarding the installation i.e. indicative of heave, sway,surge, roll, pitch and yaw; environmental data e.g. wind speed and/ordirection; tidal data; GPS and/or other positioning system data, or datafrom another source.

Alternatively or additionally, the controller may receive one or moreinput signal in the form of managed pressure drilling (MPD) system dataand/or early kick detection system (EKDS) data.

Alternatively or additionally, the controller may receive one or moreinput signal in the form of a manual confirmation input, e.g. from theoperative.

Alternatively or additionally, the controller may receive one or moreinput signal in the form of well control procedure data, e.g. a datalibrary of well control procedures from one or more operator and/orleak-off test data (e.g. pressure & depth data), or other data source.

According to a further aspect, there is provided an automated method foruse in well control.

The method may comprise providing a controller configured to receive aninput signal. The input signal may be indicative of a fluid influxcondition in a wellbore system.

The method may comprise automatically outputting one or more commandsignals initiating an initial well control protocol.

The controller may receive an input signal indicative of a fluid flowrate or fluid volumetric rate from a wellbore.

The input signal may take the form of fluid flow data from the wellbore,in particular real time fluid flow data or fluid volumetric rate fromthe wellbore. In particular, the input signal may comprise drillingfluid or mud flow or volume data.

The controller may receive one or more input signal in the form of:fluid volume data; fluid volumetric displacement data; pressure data;depth data, e.g. indicative of the rate of penetration of thedrillstring; weight data, e.g. weight of the drillstring; gas detectiondata; data indicative of the gas percentage in the drilling fluid;drilling fluid property data (e.g. indicative of fluid weight, yieldpoint and/or plastic viscosity); equipment speed data; equipmentcondition data, e.g. indicative of valve position and/or choke position;movement data regarding the installation i.e. indicative of heave, sway,surge, roll, pitch and yaw; environmental data e.g. wind speed and/ordirection; tidal data; GPS and/or other positioning system data, or datafrom another source.

Alternatively or additionally, the controller may be configured toreceive one or more input signal in the form of managed pressuredrilling (MPD) system data and/or early kick detection system (EKDS)data.

Alternatively or additionally, the controller may be configured toreceive one or more input signal in the form of a manual confirmationinput, e.g. from the operative.

Alternatively or additionally, the controller may be configured toreceive one or more input signal in the form of well control proceduredata, e.g. a data library of well control procedures from one or moreoperator and/or leak-off test data (e.g. pressure & depth data), orother data source.

According to another aspect, there is provided a processing systemconfigured to implement one or more of the previous aspects.

The processing system may comprise at least one processor. Theprocessing system may comprise and/or be configured to access at leastone data store or memory.

The data store or memory may comprise or be configured to receiveoperating instructions or a program specifying operations of the atleast one processor. The at least one processor may be configured toprocess and implement the operating instructions or program.

The at least one data store may comprise, and/or comprise a reader,drive or other means configured to access, optical storage or disk suchas a CD or DVD, flash drive, SD device, one or more memory chips such asDRAMs, a network attached drive (NAD), cloud storage, magnetic storagesuch as tape or magnetic disk or a hard-drive, and/or the like.

The processing system may comprise a network or interface module. Thenetwork or interface module may be connected or connectable to a networkconnection or data carrier, which may comprise a wired or wirelessnetwork connection or data carrier, such as a data cable, power linedata carrier, Bluetooth, Zigbee, internet connection or other similarconnection. The network interface may comprise a router, modem, gatewayand/or the like. The system or processing system may be configured totransmit or otherwise provide the signal via the network or interfacemodule, for example over the internet, intranet, network or cloud.

The processing system may comprise a processing apparatus or a pluralityof processing apparatus. Each processing apparatus may comprise at leasta processor and optionally a memory or data store and/or a network orinterface module. The plurality of processing apparatus may communicatevia respective network or interface modules. The plurality of processingapparatus may form, comprise or be comprised in a distributed orserver/client based processing system.

According to another aspect, there is provided a computer programproduct configured such that when processed by a suitable processingsystem configures the processing system to implement one or more of theprevious aspects.

The computer program product may be provided on or comprised in acarrier medium. The carrier medium may be transient or non-transient.

The carrier medium may be tangible or non-tangible.

The carrier medium may comprise a signal such as an electromagnetic orelectronic signal. The carrier medium may comprise a physical medium,such as a disk, a memory card, a memory, and/or the like.

According to another aspect, there is provided a carrier medium, thecarrier medium comprising a signal, the signal when processed by asuitable processing system causes the processing system to implement oneor more of the previous aspects.

It will be well understood by persons of ordinary skill in the art thatwhilst some embodiments may implement certain functionality by means ofa computer program having computer-readable instructions that areexecutable to perform the method of the embodiments. The computerprogram functionality could be implemented in hardware (for example bymeans of a CPU or by one or more ASICs (application specific integratedcircuits)) or by a mix of hardware and software.

Whilst particular pieces of apparatus have been described herein, inalternative embodiments, functionality of one or more of those pieces ofapparatus can be provided by a single unit, processing resource or othercomponent, or functionality provided by a single unit can be provided bytwo or more units or other components in combination.

For example, one or more functions of the processing system may beperformed by a single processing device, such as a personal computer orthe like, or one or more of each function may be performed in adistributed manner by a plurality of processing devices, which may belocally connected or remotely distributed.

The control system and method may be utilised in a range of differentapplications during operation of the oil and gas installation, asdescribed below. Each application may be implemented in a softwaremodule forming part of the control software of the control system orforming a standalone software module operatively associated with thecontrol software of the control system.

In one application, the control system may be configured to detect andreact to an influx during the process of making and/or breaking aconnection, that is adding a joint or stand of drill pipe to the top ofthe drillstring.

The control system may be coupled to a flow line sensor and may beconfigured to receive real time sensor data from the sensor, therebypermitting the control system to monitor the fluid flow rate from thewellbore during any one of the sub-phases of making the connection. Thecontrol system may be configured to determine from the sensor datawhether the fluid flow rate exceeds a preselected threshold fluid flowrate set by the operative, e.g. driller when setting up and enabling thecontrol system at the HMI arrangement, this being indicative of a fluidinflux condition in the wellbore. On determining that the fluid flowrate does exceed the preselected threshold fluid flow rate, the controlsystem may be configured to generate one or more output signal in theform of an alarm signal on the HMI arrangement. On receiving the alarmsignal, the operative, e.g. driller, may in some circumstances berequired to respond, via the HMI arrangement, with a confirmation signalconfirming that drill string pressure integrity is in place. Once thereis a positive indicator of an influx, the control system may initiate aninitial well control protocol by outputting a number of command signalsto rig and well control equipment of the oil and gas installation.

Beneficially, while the operative, e.g. driller, is performing themanual operation of making the connection, the control system may thusbe operable to detect and react to an influx that occurs during any oneof the sub-phases of making a connection.

Alternatively or additionally, the control system may be configured todetect and react to an influx during a tripping operation, that ispulling the drillstring from the wellbore and/or running the drillstring back into the wellbore, for example to replace a drill bit.

The control system may be connected to a level sensor in one or moretrip tank of the oil and/or gas installation, the level sensor may beconfigured to provide accurate real time data indicative of the fluidlevel in the trip tank. The control system may be connected to a drillbit depth sensor, the drill bit depth sensor configured to provide realtime data indicative of the depth of the drillstring in the wellbore.

The control system may be configured to determine, from the dataprovided by the drill bit depth sensor, the volumetric displacement ofthe drill pipe as it trips into and/or out of the wellbore.

The control system may be configured to compare the data from levelsensor relating to the fluid level in the trip tank with the volumetricdisplacement of the drill pipe determined from drill bit depth sensor; adeviation in the form of an increase in the fluid level in the trip tankrelative to the determined volumetric displacement being indicative ofan influx.

In the event a small deviation is detected by the control system, thecontrol system may be configured to relay a warning signal to theoperative, e.g. driller, via the HMI arrangement. In the event of alarger deviation exceeding a preselected threshold set by the operative,e.g. driller, when setting up and enabling the control system, thecontrol system may be configured to relay an alarm signal (differentfrom the warning alarm) to the operative, e.g. driller via the HMIarrangement. On receiving the alarm signal, the operative, e.g. driller,may in some circumstances be required to respond, via the HMIarrangement, with a confirmation signal confirming that drill stringpressure integrity is in place.

Once there is a positive indicator of an influx, the control system mayinitiate an initial well control protocol by outputting a number ofcommand signals to the installation and well control equipment of theoil and gas installation.

Beneficially, the control system may thus be configured to detect andreact to an influx that occurs during a tripping operation, such astripping in, tripping out, pulling wet, pulling dry, and with or withouta float in the drillstring.

In addition to being connected to the level sensor and the drill bitdepth sensor, the control system may also be connected to a flow ratesensor, thereby permitting the control system to monitor the fluid flowrate from the wellbore.

Beneficially, the addition of fluid flow rate data from the flow ratesensor permits the control system to take account of how the mudflowrate effect of tripping in and tripping out of the wellbore wouldadd or subtract to a potential influx flow rate. Alternatively oradditionally, the control system may be configured to action a furtherwell control protocol in the form of an influx circulation operation,that is flowing the influx fluid out of the wellbore.

The control system may be connected to sensors configured to monitordrill pipe pressure, casing pressure, mud pump speed, mud pump strokes,and choke position. The control system may be configured to calculatethe required information to perform the circulation operation such askill-weight, mud weight, initial circulating pressure (ICP), and slowcirculating rates (SCR).

The further well control protocol may comprise the control systemassuming control of the well control and/or drilling equipment of theinstallation. In use, when an influx has been shut-in, and theinstallation is ready to circulate out the influx, the control systemmay automatically takes control of well control and/or drillingequipment of the installation, e.g. mud pumps and the choke to performthe influx circulation operation or operations, as required, whilstmaintaining the hydrostatic pressure above the pore pressure by therequired overbalance margin, and maintaining that overbalance steady,throughout the circulation operation(s).

Beneficially, the system may thus be configured to cater for all typesof common well kill methodologies, including the Drillers' Method and/orthe Wait and Weight Method known in the art.

Moreover, the control system may be configured to identify problematicissues during well kill operations, such as plugged nozzles, plug choke,washed choked, washed drill pipe, or the like. On identification of suchissues, the control system may be configured to stop operations. Thecontrol system may relay a warning signal to the operative, e.g.driller, via the HMI arrangement, together with a recommended correctiveprocedure. The control system may automatically initiate the recommendedcorrective procedure. Alternatively, in some circumstances theoperative, e.g. driller, may be required to accept, via the HMIarrangement, the recommended solution before the control systemcompletes the well kill operation. At any time, the HMI arrangement maybe adaptable to display a range of displays in terms of pressure, time,and strokes pumps or the like.

Alternatively or additionally, the control system may be connected to amanaged pressure drilling (MPD) system of the installation.

The control system may be configured to receive a signal from the MPDsystem indicating that an influx may have been detected.

The control system may be configured to check the signal from the MPDsystem and determine from the received signal whether or not thepreselected threshold has been exceeded.

On determining that the preselected threshold has been exceeded, thecontrol system may be configured to generate one or more output signalin the form of an alarm signal on the HMI arrangement.

The control system may also initiate an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment of the oil and gas installation.

Prior to initiation of the initial well control protocol and/or prior toinitiation of the command signal to shut-in the well, the control systemmay look for further confirmation checks from the MPD system that suchan action is still valid.

Beneficially, the control system may facilitate automated well controlsystems and operations to be combined with pre-existing MPD systems onan oil and/or gas installations. Moreover, the control system may beoperable such that if the volume of an influx is greater than themaximum influx that the MPD system can circulate out (nominally 5 bbls),the control system facilitates at least the initial shut-in of the wellquickly, efficiently and with minimal or no human intervention.

Alternatively or additionally, the control system may be connected to anearly kick detection system (EKDS).

The control system may be configured to receive a signal from the EKDSindicating that an influx may have been detected.

The control system may be configured to check the signal from the EKDSand determine from the received signal whether or not the preselectedthreshold has been exceeded.

On determining that the preselected threshold has been exceeded, thecontrol system may be configured to generate one or more output signalin the form of an alarm signal on the HMI arrangement.

The control system may also initiate an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment of the oil and gas installation.

Prior to initiation of the initial well control protocol and/or prior toinitiation of the command signal to shut-in the well, the control systemmay look for further confirmation checks from the EKDS that such anaction is still valid.

The control system and/or EKDS may be connected to the sensor package,e.g.

wellsite information transfer standard markup language (WITSML) system,of the installation and/or configured to receive sensor data from thesensor arrangement, including one or more of: a flow line flow ratesensor; a pit volume totalizer (PVT) sensor; a rate of penetration (ROP)sensor; a mud pump speed (strokes per minute or SPM) sensor; a mud pumppressure (MPP) sensor; a drill string weight (DSW) sensor; a mudflowsensor; a connection gas sensor; a movement sensor; and/or a mudproperty (mud weight, plastic viscosity) sensor.

The EKDS may be connected to the HMI arrangement, in particular but notexclusively, via the control system, and may be configured so that theconfiguration of the sensor arrangement can be adjusted by theoperative, e.g. driller, via the HMI arrangement.

The EKDS may comprise control software configured to receive, compute,process and combine the sensor data from the sensor arrangement, theresultant information then being tested against pre-set criteria (of avoting/delegation form) set by the operator. If the received andprocessed sensor information satisfies the pre-set criteria, then asignal may be relayed from the EKDS to the control system to initiatethe command sequence to begin the initial well control protocol.

The sensor arrangement may comprise one or more pit volume totalizer(PVT) sensors configured to measure changes in the active mud pit fluidlevel, this being a primary kick indicator. The EKDS may be configuredto process the information obtained from the (active) PVT sensors tocompute an average fluid level height at a given time: i) whilstdrilling ahead; and ii) during connections but only after fluid flowback of the flow line. The average fluid level would need to be comparedwith previous readings (e.g. every 15 secs) and also for trendingchanges.

The sensor arrangement may comprise one or more ROP sensor, the ROPsensor configured to detect an instantaneous increase in the rate ofpenetration of the drillstring, this being a secondary kick indicator.The ROP sensor may use information from the drawworks encoder sensor(that effectively measures the block height and thus the rate at whichthe drill pipe goes into the well). Alternatively or additionally, theROP sensor may take the information from other height measurementsources.

The EKDS may be configured to process the information from the ROPsensor by comparing the current ROP with the recorded average andinstantaneous ROP values over a selected distance, e.g. the last 100 ftdrilled.

The sensor arrangement may comprise one or more SPM sensor, the SPMsensor configured to detect an increase in mud pump strokes per minute(SPM), this being another secondary kick indicator. The SPM sensor mayuse information from the active mud pump speed controller/measurementdevice.

The EKDS may be configured to process the information obtained by theSPM sensor by comparing the current total mud pumps' strokes per minutewith the recorded average and instantaneous strokes per minute over aselected past time period, e.g. the previous 5 minutes.

The sensor arrangement may comprise one or more mud pump pressure (MPP)sensor, the MPP sensor configured to detect a decrease in mud pumppressure (MPP), this being another secondary kick indicator. The MPPsensor may use information from the mud pump pressure output measurementdevice.

The EKDS is configured to process the information obtained by the MPPsensor by comparing the current mud pump pressure with the recordedaverage and instantaneous mud pump pressures over a selected past timeperiod, e.g. the previous 5 minutes.

The sensor arrangement may comprise a drill string weight (DSW) sensor,the DSW sensor configured to detect a sudden change (in particular butnot exclusively an increase in weight/reduction in buoyancy) in drillstring weight (DSVV), this being a secondary kick indicator. The DSWsensor may use information from the drillstring weight indicator.

The EKDS may be configured to process the information obtained by theDSW sensor by comparing the current DSW with the recorded average andinstantaneous drill string weights over a selected time period, e.g. theprevious 5 minutes.

The sensor arrangement may comprise a mud pump mudflow sensor, the mudpump mudflow sensor configured to measure the mud pump flow rate. Themud pump mudflow sensor may comprise a Coriolis type flowmeter on theinput to one or more of the mud pumps and/or a Coriolis type flowmeterin the flow line. Alternatively, flowrate information may be determinedby taking the input and output flowrate information feeds from thestroke counters.

The EKDS may be configured to process the information obtained bycomparing the instantaneous total flowrate going into the wellbore (bycombining mud pump input Coriolis flowrate) with the instantaneous exitflowrate coming out of the wellbore.

The sensor arrangement may comprise a connection gas sensor comprisingonline instrumentation configured to measure the size of each gas peakassociated with each successive connection.

The EKDS may be configured to process the information obtained by theconnection gas sensor by comparing the size and/or position of each gaspeak with that of the previous gas peak. An increasing trend, subject topre-set criteria, could indicate a kick, and the EKDS may process thisinformation, along with information from other module sensors.

The oil and/or gas installation may comprise a floating platform and thesensor arrangement may comprise or may be operatively associated withone or more movement sensor configured to measure movement of theplatform in terms of heave, sway, surge, roll, pitch and yaw.

The EKDS may be configured to receive and process the information fromthe movement sensor. Movement of the platform may be measured: i) usingmovement sensors; ii) using the motion reference unit (MRU) on theplatform and/or iii) predicted based upon expected Response AmplitudeOperator (RAO) values based upon the given weather and sea states. Theresultant movement information may then be used to predict the effect ofthe movement of the platform on the flowrate in the flow line and/or theactive pit fluid level. This prediction may take into effect fluidmovement lag times and the design of fluid flow lines, circulationpaths, and fluid pits on the installation, and the actual ongoingoperations on the installation (e.g. drilling ahead, tripping,connections) at the time. The overall predicted fluid flowrate and fluidlevel characteristics may then be compared with the instantaneousreadings on the platform. Comparisons may be made in terms of absolutevalues at a given time, and in terms of trending values. Deviations maybe compared against predicted information on a pre-set criteria basis.

The sensor arrangement may comprise one or more mud property sensor. TheEKDS and/or control system may be configured to take the automated mudmeasurements from an automated mud parameter measurement device, and runa series of algorithms looking at mud weights, gas cut percentages,salts, oil and water phases etc. then, as required, activate the initialwell control protocol.

Each of the EKDS and the sensors of the sensor arrangement above can beprovided as a separate module implemented in software.

The control system may be configured to detect and react to an influxduring normal circulating activities. The control system may beconnected to a flowmeter and may be configured to receive real timesensor data from the sensor, thereby permitting the control system tomonitor the fluid flow rate from the wellbore during circulation. Thecontrol system may also be connected to a mud pump speed sensorconfigured to measure the speed of the mud pumps. The control system maybe configured so that the base level flowrate held by control system isadaptable to, typically frequent, alterations to the mud pumpspeed/flowrate made by the operative, e.g. driller. The incrementalflowrate that triggers the initial well control protocol may be inputtedas a percentage increase. However, it will be understood that theincremental flowrate that triggers the initial well control protocol mayalternatively be input as a fixed incremental amount above theinstantaneous flowrate.

The control system may be configured to monitor the well when static.The control system may be connected to a level sensor configured tomeasure fluid level in the trip tank, a flow line sensor configured tomeasure fluid flow rate, and a sensor configured to measure the activepit volume.

During initial set up, the operative, e.g. driller, may preselect, viathe HMI arrangement, which of the sensors are monitored. The decision asto which of the sensors are monitored may depend on whether theoperation is being carried out in open hole or cased hole and/or how themud flow system is lined up. The control system may be configured todetermine from the sensor data received from the selected sensors,whether a detected volume change in the trip tank and/or in the activepit, or a detected flowrate change in the flow line exceeds apreselected threshold set by the operative, e.g. driller, when settingup and enabling the control system, this being indicative of a fluidinflux condition in the wellbore. On determining that the fluid flowrate does exceed the preselected threshold fluid flow rate, the controlsystem may be configured to generate one or more output signal in theform of an alarm signal on the HMI arrangement. The control system mayinitiate an initial well control protocol by outputting a number ofcommand signals to the installation and well control equipment.

The control system may be connected to a level sensor configured tomeasure fluid level in the trip tank. The control system may beconfigured to determine from the sensor data received from the sensors,whether a detected volume change in the trip tank exceeds a preselectedthreshold set by the operative, e.g. driller, when setting up andenabling the control system at the HMI arrangement, this beingindicative of a fluid influx condition in the wellbore. On determiningthat the detected volume change does exceed the preselected thresholdfluid flow rate, the control system may be configured to generate one ormore output signal in the form of an alarm signal on the HMIarrangement. The control system may initiate an initial well controlprotocol by outputting a number of command signals to the installationand well control equipment.

Beneficially, the control system can be utilised to monitor inflow testson liner packers or on certain lower completions.

As described above, following initiation of the initial well controlprotocol the control system may be configured to initiate a further wellcontrol protocol in the form of a fluid pumping operation.

The control system may be configured to monitor the well during such afluid pumping operation.

The control system may be connected to a sensor arrangement comprisingone or more flow rate sensor, casing pressure gauge, mud pump speed andpressure sensors, mud property sensor. The control system may alsoreceive leak-off test data and drill bit depth data.

Beneficially, the control system may be configured to limit the influxsize that is shut-in by turning off the mud pump(s) slowly rather thanwith the normal turn on/off approach. This means that the loss ofhydrostatic pressure due to the mud pump(s) being turned off (i.e. lossof the equivalent circulating density (ECD) occurs more slowly, thuslimiting the size of influx coming into the wellbore and allowingpressures to equalise more quickly in the wellbore after shutting in.The control system may be configured to ensure that the Leak Off Testvalue (LOT) at the previous casing shoe will not be exceeded.

The control system may be connected to a sensor arrangement comprisingone or more flow rate sensor, casing pressure gauge, mud pump speed andpressure sensors, mud property sensor. The control system may alsoreceive drill bit depth data.

Beneficially, the control system may thus address a problem that isrelatively common in clastic formations and in High Pressure HighTemperature (HPHT) wells, called Ballooning, whereby the dynamic mudweight pressure approaches the formation pressure resulting of smallamounts of drilling fluid leaking into the formation. On a connection,when the mud pumps are turned off and the drilling fluid pressurereduces, the leaked fluid will flow back into the wellbore. This can bea substantial volume over a long open hole section. It can be difficultto decipher this flow back from a true influx. The flow back will give asignature “flowrate with time” at surface.

During normal drilling operations, the control system may measure everysignature on every connection, the control system determining from thedata received from the sensor arrangement and optionally utilising anArtificial Intelligence algorithm, an expected signature at the nextconnection, the expected signature taking into account the extra amountof ballooning-prone formation now exposed.

The control system may compare the actual flow back signature at surfacewith the predicted signature, and subject to certain pre-set criteria,will action the initial well control protocol to shut in the well.

The control system may be configured to detect and react to an influxduring a swabbing operation. The control system may be connected to asensor arrangement, comprising one or more mud property sensor. Thecontrol system may also receive wellbore dimension data, drill bit depthdata and leak-off test data. The control system may be configured tocalculate the maximum pull out of hole (POOH) speed on a continuousbasis. In the event an influx is detected, the control system may beconfigured to generate one or more output signal in the form of an alarmsignal on the HMI arrangement. The control system may initiates aninitial well control protocol by outputting a number of command signalsto the installation and well control equipment to shut in the wellbore.

Beneficially, the control system may permit the POOH speed to bemaximised while avoiding or at least mitigating the risk of swabbing aninflux into the wellbore.

The control system may be configured to detect and react to an influxduring a run-in operation. The control system may be connected to asensor arrangement, comprising one or more mud property sensor. Thecontrol system may also receive wellbore dimension data, drill bit depthdata and leak-off test data. Surging is when the bottom hole pressure isincreased due to the effects of running the drill string too fast in thewellbore. Down hole mud losses may occur if care is not taken andfracture pressure is exceeded while running in hole (RIH). The controlsystem may be configured to calculate the maximum RIH speed on acontinuous basis. In the event an influx is detected, the control systemmay be configured to generate one or more output signal in the form ofan alarm signal on the HMI arrangement. The control system may initiatean initial well control protocol by outputting a number of commandsignals to the installation and well control equipment to shut in thewellbore.

The control system may be configured to detect and/or react to aninflux, for example, during a run-in operation.

The control system may be connected to a sensor arrangement. The sensorarrangement may comprise one or more of a mud property, flowrate, speedand/or pressure sensor or the like. The control system may receivewellbore dimension data, casing depth data and/or leak-off test data orthe like.

The control system may be configured to determine from the received datawhether an influx is occurring. In the event an influx is detected, thecontrol system may be configured to generate one or more output signal,which may be in the form of, for example, an alarm signal on the HMI inthe control station. The alarm signal may comprise an audible and/orvisual alarm signal. The control system may initiate an initial wellcontrol protocol by, for example, outputting a number of command signalsto the installation and/or well control equipment to shut in thewellbore.

The control system may detect and/or react to an influx during therunning of casing or liners.

The control system may receive wellbore dimension data, completion depthdata and/or leak-off test data or the like.

The control system may detect and/or react to an influx during therunning of completions.

The control system may detect and/or reacts to an influx during thecementing of casing or liner.

The control system may receive flowrate data. The flow rate data may bewith or without the riser. The control system may receive wind directiondata.

The control system may be designed for drilling the upper sections ofthe wellbore. The control system may be designed for drilling the uppersections without the BOP. The control system may be designed fordrilling where it may not be safe to shut in the well due to, forexample, the risk of casing shoe fracture. If the drilling encounters apocket of shallow gas, the control system may detect a high mud flowratereturn out of the well annulus. The methodology to detect the flowratemay be determined by the drilling mode; i.e. whether or not a riser isin place.

The control system may relay an alarm signal to the driller. The alarmsignal may be related via the HMI arrangement.

The control system may continually and/or continuously pre-assess winddirection. The wind direction may be assessed at all times. Followingthe alarm signal, the control system may send a signal to open thedownwind overboard line valve. A signal may be sent to close thediverter. Closing the diverter may divert the flow away from theinstallation.

The control system may be connected to a sensor arrangement. The sensorarrangement may comprise trip tank pump and/or level sensors.

For installations without a riser gas handling system, once BOPs areactivated by the control system, the control system may automaticallyswitch on the Trip Tank (TT) pump and/or switch the surface valves tomonitor the riser contents.

The control system may monitor the trip tank. If the trip tank levelincreases over a period of time, the control system may determine thatthe BOP has not closed properly, sufficiently or completely and/or thatthere may be migrating gas in the riser.

The control system may initiate an increase in the closing pressure onthe BOP.

Alternatively or additionally, the control system may initiate closureof an alternative BOP and/or may initiate directing the flow to the poorboy degasser (PBD) and/or initiate operation of the diverter system(having also assessed wind direction).

The consideration of routing may take account of the capacity of the PBDfrom the vessel throughput aspect and/or from a U-tube aspect.

If either of these are exceeded, the control system may initiatediversion of the flow through the diverter.

In either case, the control system may close another BOP, e.g. analternative BOP and/or may automatically function the riser gas annularsimultaneously.

The control system may be connected to a BOP sensor.

The control system may be configured to detect the pressure below aclosed BOP. The control system may, for example, on detection ofpressure below a closed BOP, execute an interlock to prevent any partyfrom opening the BOP.

The control system may be connected to a library, of operator and/ordrilling contractor well control procedures for, for example, tripping,connections drilling or the like.

The link to the library may permit sequencing of the control systemoperations to be tailored to a given operator and/or drillingcontractor's well control procedures.

The control system may be connected to a multi-rig sensor arrangement.

The control system may be configured to determine, for example, usingthe data from the multi-rig sensor arrangement, the particular phase ofwell construction at a given time. The control system may automaticallyensure that the appropriate control system module is in operation forthat phase.

The control system may be switched on at all times. Alternatively, thecontrol system may be switched on only when needed, or in use.

The control system may be configured to receive at least one of tidaldata, selected space-out position data and time linking data.

The control system may be configured, based on the at least one of tidaldata, selected space-out position data and time linking data, toautomatically adjust the space-out position in response to changes intide.

In use, the driller may select the space out positions on the controlsystem via the HMI arrangement at initial set-up. Those positions may belogged, as may be the time at which they were logged. Where certainchanges of tide make a previously selected space-out position unusable,the control system may relay an alter signal to the drill requesting anupdated set of space-out positions.

Beneficially, the system may be particularly adapted for use on afloating rig that is subject to a large tidal range.

The control system may be configured to receive at least one of BOPdimension data, tidal data, space-out position data and BOP preferenceinformation.

The control system may be configured, based on the at least one of BOPdimension data, tidal data, space-out position data and BOP preferenceinformation, to automatically assess the position of the tool joint inrelation to the exact BOP configuration on the installation, and to thenauto-select which is the best BOP to close at any given time.

The control system may be configured to receive at least one of wirelinedepth meter data, rig floor depth data and safety distance data.

In use, the control system may be configured, based on the at least oneof wireline depth meter data, rig floor depth data and safety distancedata, to relay an alert signal to the driller, via the HMI, and/orwireline supervisor via a suitable data link, when pulling out of holeindicating that the tooling is near/at surface or is becoming held upand/or when running in hole that is close to target depth, or if itbecome held up.

Beneficially, the system may provide an automated warning for control ofslickline, wireline, coil tubing etc.

The control system may be connected to a flowrate sensor. The sensor maybe associated with the coiled tubing system of the installation.

In the event an influx is detected during coiled tubing operations, thecontrol system may be configured to generate one or more output signalin the form of an alarm signal on the HMI arrangement. The alarm signalmay comprise audible and/or visual alarm signals.

The control system may initiate an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment, for example including the BOP operatively associatedwith the coiled tubing, to shut in the wellbore.

The control system may be connected to a flowrate sensor. The sensor maybe associated with the wireline system of the installation.

In the event an influx is detected during wireline operations, thecontrol system may be configured to generate one or more output signalin the form of an alarm signal on the HMI arrangement in the controlstation. The alarm signal may comprise audible and/or visual alarmsignals.

The control system may initiate an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment, for example including the BOP operatively associatedwith the wireline, to shut in the wellbore. The control system may beconfigured to receive GPS and/or other positioning system data and/orvessel propulsion control data. The control system may be configured,based on the received GPS and/or other positioning system data and/orvessel propulsion control data, to output a number of command signals tothe installation and well control equipment to close blind/shear,disconnect the Lower Marine Riser Package (LMRP), and performinstallation drive off.

The control system may be configured to receive GPS and/or otherpositioning system data and/or vessel propulsion control data, and/orgas sensor data.

The control system may be configured, based on the received GPS and/orvessel propulsion control data, and/or gas sensor data, to output anumber of command signals to the installation and well control equipmentto close the blind/shear, disconnect the Lower Marine Riser Package(LMRP), and drive off.

The control system may be configured to receive GPS and/or otherpositioning system data and/or vessel propulsion control data, and/orexcursion limit pre-integrity failure data.

The control system may be configured, based on the received GPS and/orother positioning system data and/or vessel propulsion control data,and/or excursion limit pre-integrity failure data, to output a number ofcommand signals to the rig and well control equipment 102 to close theblind/shear, disconnect the Lower Marine Riser Package (LMRP), andperform a drive off.

Beneficially, the control system may be configured to shut-in the wellwhere e.g. an excursion of the installation (e.g. due to a failedDynamic Positioning system) reaches a point where the integrity of theriser/BOP system would otherwise be compromised.

The control system may be connected to a BOP sensor arrangement. The BOPsensor arrangement may be configured to receive data from the BOP.

The control system may be configured, based on the BOP sensorarrangement, to automatically and continually perform BOP fault findingand, in the event of an influx, automatically a required change (e.g.Pod Change or next lower BOP activation) to make the BOP function.

The control system may be connected to a sensor arrangement configuredto receive data from all well control equipment on the installation.

The control system may be configured to monitor the status/health of keywell control equipment (BOP, mud pumps, choke) and the associatedequipment instrumentation on the HMI arrangement, and relay an audiblealarm and/or visual signal in the event of a discrepancy in performancebeyond a selected threshold.

The control system may be connected to a sensor arrangement configuredto receive flowmeter data, trip tank sensor data, and active pit volumesensor data.

The control system may be configured to monitor the wellbore during aplug drill out operation during well decommissioning.

This is particularly important where previously-installed downholebarriers may be of questionable nature, or where insufficient mud weightcannot be properly achieved prior to drilling out a plug with apotential high pressure below.

The control system may be connected to a sensor arrangement configuredto receive flowmeter data, trip tank sensor data, and/or active pitvolume sensor data.

The control system may be configured to output command signals to amechanical arm, to be used for example to automatically install, torqueup, and/or close a full opening safety valve (FOSV).

The system topology may be implemented within the control software ofthe control system or may be a standalone module.

The control system may comprise or may be operatively associated with asoftware module that may determine the health of a flow meter e.g. themodule, flowmeter paddle, the health of a Coriolis meter, or any otherflow meter. For example, the control system may be configured todetermine the health of a flow meter where, for example: there are nofluctuations in flow rate detected over a specified period; the flowmeter outputs a minimum reading when mud pumps are operating well abovethat level; the flow meter outputs a maximum reading when the mud pumpsare operating well below that level; and/or the flow meter outputs asignificantly different reading to previously observed recent readings.

The control system, on identifying a deviation in the health of the flowmeter, may then relay a warning signal to the operative via the HMIarrangement.

The control system may comprise or may be operatively associated with asoftware module that can record data critical to the decision to shut-inthe well and may record all relevant instrumentation, actions and timingthroughout the process of automatically safely shutting in the well toprovide historical record for future analysis of the effectiveness ofthe system responses, and any human interventions.

The control system may pass data in real time over a secure internetlink enabling management to view status of control system at any time.This may provide all data critical to the decision to shut-in the wellensuring a safe remote record all relevant instrumentation, actions andtiming throughout the process of automatically safely shutting in thewell to provide historical record for future (and immediate) analysis ofthe effectiveness of the system responses, and any human interventions.

The control system program may be accessible over a secure internet linkenabling technical support for fault finding diagnostics, configurationand/or upgrades to be affected from a remote location. This may provideenhanced efficiency of commissioning and support to ensure maximumup-time for the control system equipment, and may reduce the need forhigh skilled technical support in remote locations.

The control system may comprise or may be operatively associated with abiometric security software module. The biometric security module may beused where pre-operation or post-operation authorisation is required(e.g. opening of a closed BOP). The biometric security module mayrequire e.g. thumb-print, or face recognition identification of higherauthority (e.g. a toolpusher), on the HMI arrangement.

The control system may be configured to allow the driller the ability toshut-in the wellbore without having to switch the control system offvery quickly, e.g. in an emergency situation. There may be a button onthe HMI arrangement that may enable a one or two touch action to performthe full shut in sequence including space out, stop drilling equipmentand/or close the BOP.

It will be understood that any one of the features defined above ordescribed below may be utilised in isolation or in combination.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects will now be described by way of example withreference to the accompanying drawings, of which:

FIG. 1 shows an oil and gas installation comprising an automated wellcontrol system;

FIG. 2 shows an enlarged view of the driller's cabin of the oil and gasinstallation shown in FIG. 1;

FIG. 3 is a diagrammatic view of the automated well control systemtopology, showing the integration of the automated well control systemwith components of the oil and gas installation shown in FIG. 1;

FIG. 4 shows a schematic view of components of the automated wellcontrol system;

FIG. 5 shows components of the automated well control system;

FIG. 6 shows a flow chart showing a method for use in well control;

FIG. 7 is a flow chart showing a further method for use in well control;

FIGS. 8A and 8B are flow charts together showing an alternative methodfor use in well control;

FIG. 9 is a pore pressure/fracture gradient diagram illustrating themethod shown in FIGS. 8A and 8B;

FIG. 10 is a flow chart showing a further method for use in wellcontrol;

FIG. 11 is a flow chart showing a further method for use in wellcontrol;

FIG. 12 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 13 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 14 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 15 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 16 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 17 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 18 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 19 shows a diagrammatic view of the EKDS shown in FIG. 18;

FIG. 20 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 21 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 22 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 23 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 24 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 25 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 26 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 27 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 28 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 29 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 30 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 31 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 32 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 33 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 34 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 35 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 36 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 37 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 38 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 39 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 40 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 41 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 42 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 43 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 44 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 45 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;

FIG. 46 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1;and

FIG. 47 is a diagrammatic view of an alternative automated well controlsystem topology, showing the integration of the automated well controlsystem with components of the oil and gas installation shown in FIG. 1.

DETAILED DESCRIPTION OF THE DRAWINGS

Referring first to FIGS. 1 and 2 of the accompanying drawings, there isshown an oil and/or gas installation 10 utilising an automated wellcontrol system (represented generally at 12 in FIG. 2). As shown in FIG.1, the oil and/or gas installation 10 comprises a floating platform 14which is coupled to a subsea wellhead 16 of wellbore 18 by a marineriser 20. A driller's control station 22 is located on a drill deck 24of the platform 14 and, as shown in FIG. 2 of the accompanying drawings,the control system 12 communicates with the driller 26 via human machineinterface (HMI) 28 located within the driller's control station 22. Inthe illustrated system 12, the control system 12 communicates with theHMI 28 via an optical fibre communication arrangement 30, although itwill be recognised that other wired or wireless communicationarrangements may be provided.

FIG. 3 of the accompanying drawings shows a diagrammatic view of thesystem topology of the control system 12, illustrating the integrationof the control system 12 with components of the oil and/or gasinstallation 10 shown in FIG. 1.

As shown in FIG. 3, the control system 12 is operatively coupled to flowsensors 32 of mud pump system 34 and, in use, the control system 12 isconfigured to receive real time sensor data 36 from the sensors 32,thereby permitting the control system 12 to monitor the fluid flow ratefrom the wellbore 18 in FIG. 1.

As also shown in FIG. 3, the illustrated control system 12 is alsooperatively coupled to a rig data system 38 and, in use, is configuredto receive real time downhole data 40 from the rig data system 38.

In use, the control system 12 is configured to determine from the sensordata 32 whether the fluid flow rate exceeds a preselected thresholdfluid flow rate set by the driller 26 when setting up and enabling thecontrol system 12 at the HMI 28, this being indicative of a fluid influxcondition in the wellbore 12.

On determining whether the fluid flow rate seen by the sensors 32 doesexceed the preselected threshold fluid flow rate, the control system 12is configured to initiate an initial well control protocol by outputtinga number of command signals to components of the installation 10 as willbe described. In the illustrated control system 12, for example, ondetermining that the fluid flow rate seen by the sensors 32 does exceedthe preselected threshold fluid flow rate, the control system 12implements an initial well control protocol in the form of a wellshut-in procedure involving:

communicating a command signal 42 to controller 44 of drawworks 46 toinstruct the drawworks 46 to raise the drill string 48 (shown in FIG. 1)off the bottom of the wellbore 18;

communicating a command signal 50 to controller 52 of top-drive 54 toinstruct the top drive 54 to stop rotating;

communicating a command signal 56 to controller 58 of mud pumps 60 toinstruct the mud pumps 60 to stop pumping fluid into the wellbore 18;and

communicating a command signal 62 to controller 64 of blow out preventer(BOP) 66 to instruct the BOP 66 to close and thereby shut-in thewellbore 12.

The controllers 44, 52, 58, and 64 each control components 46,54,60 and66 respectively. It will be recognised that in other instances, forexample in traditional installations, the components may be directlycontrolled rather than via controllers.

As shown in FIG. 3, the control system 12 is also operatively coupled tochoke manifold 68 and choke panel 70.

FIGS. 4 and 5 of the accompanying drawings show components of theautomated well control system 12 in more detail. As shown, the controlsystem 12 comprises a controller 72 which in the illustrated system 12takes the form of two synchronised Programmable Logic Controllers (PLCs)74 each containing a CPU 76 and a memory unit 78. Each PLC 74 is coupledto a power supply module 80 operating on 24V DC. The PLCs 74 are linkedvia a fibre optic cable 82. However, it will be understood that anysuitable wired or wireless communications protocol may be utilised.

The control system 12 further comprises an input/output module 84 forproviding communication between the controller 72 and the components ofthe installation 10 in the manner described above with reference to FIG.3.

The input/output module 84 and the PLCs 74 of the controller 72communicate via a Process Field Bus (Profibus) interface 86. However, itwill be understood that any suitable wired or wireless communicationsprotocol may be utilised.

The control system 12 further comprises an Industrial Personal Computer(IPC) 88, the IPC 88 operable to run the software for the HMI 28 (shownin FIG. 2). The control system 12 further comprises an Ethernet switch90 facilitating communication with multiple devices simultaneously.

FIG. 4 also shows the fibre optic cable 30 for linking the IPC and theHMI 28. As shown in FIG. 5, the control system 12 further comprises anuninterruptable power supply (UPS) module 92 and battery 94. In use, theUPS 92 and battery 94 provide back-up power to the 24V DC components ofthe control system 12 in the event of power failure.

The control system 12 further comprises an Intrinsically Safe (IS)barrier unit 96 configured to convert the 24V power supply into one thatis safe for use in a hazardous area by virtue of the converted supplynot being powerful enough to cause an ignition source, spark or thelike.

The control system 12 further comprises an AC/DC converter 98 forconverting a 240V AC supply to a 24V DC supply for the PLCs.

Operation of the control system 12 will now be described with referenceto FIGS. 6, 7 and 8 of the accompanying drawings.

As shown in FIG. 6, the control system 12 is first set up and enabled bythe driller 26 at the HMI 28.

The driller 26 then controls the drilling equipment, including amongstother things the drawworks 46, the top-drive 54, and mud pumps 60, tobegin drilling operations. At this point, from the driller's 26perspective the control system 12 is operating in the background, thatis the drilling operations are not affected by the control system 12.However, the control system 12 is monitoring the fluid flow rate, inparticular mud flow returns rate from the wellbore 18. The fluid flowrate data may be sourced from the rig data system (not shown).Alternatively, for older installations which do not employ a rig datasystem the fluid flow rate data may be sourced directly frominstrumentation.

On detecting an increase in fluid flow rate from the wellbore 18 whichexceeds a preselected threshold set by the driller 26 when setting upand enabling the control system 12, the control system 12 generatesoutput signals in the form of an audible alarm and visual warning on theHMI in the control station 22.

The control system 12 also implements the initial well control protocolin the form of a well shut-in procedure, as will be described below.

The control system 12 generates command signal 42 to the controller 44of the drawworks 46 to instruct the drawworks 46 to raise the string 48off the bottom of the wellbore 18.

Data on the height of the drawworks 46 will be sourced from thedrawworks controller 44.

When the drawworks reaches the first available set height, the controlsystem controller will command the drawworks controller to stop raisingthe drill string 48.

The control system 12 also generates command signal 50 to the top drivecontroller 52 to instruct the top drive 54 to stop rotation.

The control system 12 also generates command signal 56 to the mud pumpscontroller 58 to stop a number of pre-selected mud pumps 60.

After a pre-set delay time set by the driller 26 when setting up andenabling the control system 12, if the control system 12 detects thatthe flow rate remains above the preselected threshold flow rate, orfollowing confirmation the mud pumps 60 have stopped and a further timedelay has been completed, if flow has not reduced to a negligible levelthe system 12 determines that an influx condition is present andongoing. In the illustrated method, the pre-set delay time set by thedriller 26 when setting up and enabling the control system 12 is 1second and the further time delay is 30 seconds. The pre-set delay timeand further time delay are adjustable by the driller 26 when setting upthe control system 12, but occur automatically once the control system12 has been enabled.

On determining that an influx condition is present, the control systemcontroller 72 will generate a command signal to the BOP 66 toimmediately close the annular preventer or pipe ram (depending on whichoption has been preselected by the driller during set up of the controlsystem 12).

Once the BOP 66 has been closed, and the wellbore 18 shut-in, the alarmsignal is cancelled and the control system controller 72 returns to adormant condition, i.e., continues to monitor data from the othersystems but makes no operational demands on the components of theinstallation 10 until the driller 26 initiates an operation to circulatethe influx as will be described below with reference to FIG. 7. Thesystem 12 may be dormant from 30 minutes to 2 hours depending on whatoption has been chosen by the driller 26 when setting up the system 12.

As shown in FIG. 7, after the wellbore 18 has been shut in, the system12 performs the necessary calculations to produce a kill sheet used toconfirm pressure and required details required to circulate out theinflux from the wellbore 18 automatically.

The system logic determines max pressure on the drill pipe and casingsides, using the auto choke to maintain the safety margins pressurerequired from the drill pipe and casing sides.

The choke or kill line valve on the choke manifold 70 is opened to thenline up the choke panel 68, to monitor drill pipe and casing pressuresuntil they stabilise.

Once drill pipe and casing pressures have stabilised, on the presetinstructions from the HMI 28 the system 12 will automatically start theselected mud pumps 60 to circulate the influx out of the wellbore 18 ata set speed pre-selected by the driller 26 on the HMI 28. By way ofexample, the set speed may be in the range of 5 strokes per minute (SPM)up to 40 strokes per minute (SPM).

The control system 12 will automatically operate the choke valve and/orpanel 68 to the correct opening or closing percentages depending on thesafety margins required in the wellbore 18, until the influx iscirculated out of the wellbore 18.

The control system 12 continuously monitors the actual versus calculatedpressures and automatically adjusts the choke valve or panel 68 openingor closing positions to ensure the correct pressures are maintaineduntil the influx is safely circulated out of the wellbore 18.

Referring now to FIGS. 8A and 8B of the accompanying drawings, there isshown an alternative automated method for use in well control.

As shown in FIG. 8A, the control system 12 is first set up and enabledby the driller 26 at the HMI 28.

The driller 26 then controls the drilling equipment, including forexample the drawworks 46, the top drive 54, and mud pumps 60, to begindrilling operations. At this point, from the driller's 26 perspectivethe control system 12 is operating in the background, that is thedrilling operations are not affected by the control system 12. However,the control system 12 is monitoring the fluid flow rate, in particularmud flow returns from the wellbore 18. The fluid flow rate data may besourced from the rig data system 38. Alternatively, for olderinstallations which do not employ a rig data system 38 the fluid flowrate data may be sourced directly from instrumentation.

On detecting an increase in fluid flow rate from the wellbore 18 whichexceeds a preselected threshold set by the driller 26 when setting upand enabling the control system 12, the control system 12 generatesoutput signals in the form of an audible alarm and visual warning on theHMI 28 in the control station 22.

The control system 12 also implements the initial well control protocolin the form of a well shut-in procedure, as will be described below.

The control system 12 generates command signal 42 to the controller 44of the drawworks 46 to instruct the drawworks 46 to raise the string 48off the bottom of the wellbore 18.

Data on the height of the drawworks 46 will be sourced from thedrawworks controller 44.

When the drawworks 46 reaches the first available set height, thecontrol system controller 72 will command the drawworks controller 44 tostop raising the drill string 48.

The control system 12 also generates command signal 50 to the top drivecontroller 52 to instruct the top drive 54 to stop rotation.

The control system 12 also generates command signal 56 to the mud pumpscontroller 58 to stop the pre-selected mud pumps 60. However, in thealternative method illustrated in FIG. 8A, one of the mud pumps 60continues to pump, for example at 30 strokes per minute (SPM).

On determining that an influx condition is present, the control systemcontroller 72 will generate command signal 62 to the BOP 66 toimmediately close the annular preventer or pipe ram (depending on whichoption has been preselected by the driller 26 during set up of thecontrol system 12).

Once the BOP 66 has been closed, and the wellbore 18 shut-in, the mudpump 60 continues to pump at a low rate, e.g. 30 strokes per minute,until the appropriate drill pipe pressure is achieved.

The appropriate drill pipe pressure to which the mud pump 60 continuesto pump is determined as the lower of Pmax and Psc, where Pmax is themaximum pressure that can be achieved without damaging the formation,and where Psc is the pressure at which the pumped fluid equals thepressure of the influx (the “supercharge” pressure).

As described above, during the well construction process the MaximumAllowable Annulus Surface Pressure (MAASP) must not be exceeded,otherwise an underground blowout may be initiated. This may lead to abreach to surface and must be avoided.

Pmax may be defined with reference to MAASP by equation (1):

Pmax=MAASP−100 psi  (1)

MAASP itself may be calculated from equation (2):

MAASP=(FG−MW)×0.052×TVD,  (2)

-   -   where FG is the fracture gradient,    -   where MW is the mud weight in pounds per gallon,    -   where TVD is the total vertical depth of the casing shoe in ft

Psc may be calculated from equation (3):

Psc=X×0.052×TVD,  (3)

-   -   where TVD is the total vertical depth of the casing shoe in ft,    -   where X is the additional mud weight in pounds per gallon (ppg)        which the drilling engineer and geologist determine is derived        from the maximum probable increase in mud weight for the hole        section being drilled. It is determined by hole section and        depth of the well. For instance a relatively shallow hole        section, down to 2,500 ft in an area where the pore pressure is        well known might have an X value of 0.5 ppg. In a deeper hole        section, 12,000 ft with a large potential for higher pore        pressures, may have an X value of 4 ppg.

The control system 12 logic determines if Pmax or Psc is lower andcontinues pumping to whichever is the lower pressure.

The mud pump 60 is then slowed down incrementally from 30 strokes perminute to 20 strokes per minute to 10 strokes per minute over the last100 psi. Within 100 psi, the system 12 reduces to 20 strokes per minute.Within 50 psi it reduces to 10 strokes per minute.

At the predetermined value the mud pump 60 stops pumping.

The alarm is cancelled and the control system controller 72 returns to adormant condition, continues to monitor data from the other systems butmakes no operational demands on the other equipment.

Having addressed the influx, and when safe to do so, operations may thenbe resumed by the driller 26.

Beneficially, the fluid pumping operation of FIGS. 8A and 8B reduces orminimises the volume of the influx. Minimising the influx volume hasseveral advantages. For example, a reduced influx volume may result inlower pressure being exerted on the wellbore 18 and the rig equipment.There is also a reduced risk of getting stuck and other hole problems.More options to kill the well become available, particularly using thebull-heading technique to displace the influx back into the donorformation. The system 12 assures the operator that the influx volumewould be significantly reduced, in particular but not exclusively to amaximum of five barrels of influx.

Referring now also to FIG. 9 of the accompanying drawings, which shows apore pressure/fracture gradient diagram of a given wellbore, a kickevent is detected at 11,000 ft (3.35 km) whilst drilling with 14.2 ppg(pounds per gallon) drilling mud.

The shoe at 9,000 ft has a fracture gradient of around 15.2 ppg.

The MAASP is therefore 1 ppg×0.052×9,000 ft=468 psi.

The uncertainty of the pore pressure, determined by the operationsgeologist and drilling engineer was 2 ppg, meaning the probability ofthe anticipated pore pressure to be greater than 2 ppg is very low.Therefore, X=2 ppg.

Pmax=468 psi-100 psi=368 psi with 14.2 ppg mud.

Psc=2 ppg x 0.052×9000 ft=936 psi, with 14.2 ppg mud.

Thus, after the wellbore has been the shut in, the selected mud pump 60continues pumping to 368 psi. The selected mud pump 60 is then stoppedas described above.

FIG. 10 of the accompanying drawings shows a flow chart showing afurther method for use in well control. In this method, the drill pipeis being run in or being pulled out of the wellbore 18.

As shown in FIG. 10, the control system 12 is set-up & enabled by thedriller 26 at the HMI 28.

The driller 26 then controls the drilling equipment and begins trippingoperations.

The driller 26 enters differential mud volume data into the HMI 28 asthe drill pipe is run in or pulled out of the wellbore 18.

The control system 12 receives a signal from a sensor in the trip-tank,while the drill pipe is being pulled out or run in hole.

When the sensor identifies an inconsistency in mud volumes, the driller26 is alerted on the HMI 28.

After a pre-set time delay, if the threshold is still exceeded or if,following a further time delay, flow has not reduced to a negligiblelevel, the system 12 determines that an influx is ongoing, and initiatesthe initial well control protocol.

The control system 12 sends a command to the drawworks controller 44instructing it to immediately lower the drawworks 46. When the drawworks46 reaches the connection height, the control system 12 commands thedrawworks controller 44 to stop.

As the initial well control protocol progresses, the HMI 28 displays thesteps of the process, e.g. “Stab in Full Open Safety Valve”, “Make UpValve”, “Close Valve”. Once the three actions are taken, the driller 26presses the validation button on the HMI 28.

The control system PLC 74 then commands the BOP controller 64 toimmediately close the annular preventer of BOP 66.

The alarm is cancelled and the control system controller 72 returns to adormant condition, continues to monitor data from the other systems butmakes no operational demands on the other equipment.

Having addressed the influx, and when safe to do so, operations may thenbe resumed by the driller 26.

FIG. 11 is a flow chart showing a further method, for use when drillpipe connections are made for drilling-in the wellbore 18.

The control system 12 is first set up and enabled by the driller 26 atthe HMI 28. The driller 26 then controls the drilling equipment,including for example the drawworks 46, the top drive 54, and mud pumps60, to begin drilling operations. At this point, from the driller's 26perspective the control system 12 is operating in the background, thatis the drilling operations are not affected by the control system 12.However, the control system 12 is monitoring the fluid flow rate, inparticular mud flow returns from the wellbore 18. The fluid flow ratedata may be sourced from the rig data system 38. Alternatively, forolder installations which do not employ a rig data system 38 the fluidflow rate data may be sourced directly from instrumentation.

If the control system 12 determines from the input signal received fromsensor 32 that the fluid flow rate exceeds a pre-set threshold flowratefor when the drill pipe is stationary, the control system 12 generatesoutput signals in the form of an audible alarm and visual warning on theHMI 28 in the control station 22.

The control system 12 then sends a signal to a control arm to install avalve on the top of the drill pipe.

When the valve is installed, the control system 12 will send a commandto BOP controller 64 to close the BOP 66.

The above system and method provides a number of benefits overconventional well control techniques. For example, in addition toproviding automated detection and actioning of the initial well controlprotocol, e.g. shut-in procedure, the system and method providesautomation of the maximum pressure calculations on a continuous basis,since mud weight (MW) varies during the drilling process and the system12 is configured to continuously monitor the mud weight, e.g. from theinstallation sensor arrangement.

It will be recognised that the above is merely exemplary and thatvarious modifications may be made without departing from the scope ofthe claims.

For example, the control system 12 may be configured to additionallymonitor the level in the mud pit as indicative of an increase in fluidflow rate from the wellbore 18.

The control system 12 may also read the pump pressure on a continuousbasis and present this to the driller 26 in order to communicate theproximity to shoe fracture pressures.

It will be recognised that the control system 12 may be utilised in arange of different applications during operation of the oil and gasinstallation 10, as described below.

For example, FIG. 12 of the accompanying drawings shows a diagrammaticview of a system topology of the control system 12, illustrating theintegration of the control system 12 with components of the oil and/orgas installation 10, the control system 12 configured to detect andreact to an influx during the process of making and/or breaking aconnection, that is adding a joint or stand of drill pipe to the top ofthe drillstring.

As shown in FIG. 12, the control system 12 is coupled to flow linesensor 100 and is configured to receive real time sensor data from thesensor 100, thereby permitting the control system 12 to monitor thefluid flow rate from the wellbore 18 during any one of the sub-phases ofmaking the connection. The flow line sensor 100 may be identical to thesensor 32 described above, or may take the form of another flow ratesensor.

The control system 12 is configured to determine from the sensor datawhether the fluid flow rate exceeds a preselected threshold fluid flowrate set by the driller 26 when setting up and enabling the controlsystem 12 at the HMI 28, this being indicative of a fluid influxcondition in the wellbore 12.

On determining that the fluid flow rate does exceed the preselectedthreshold fluid flow rate, the control system 12 is configured togenerate one or more output signal in the form of an alarm signal on theHMI 28 in the control station 22. In the illustrated system, the alarmsignal comprises audible and visual alarm signals.

On receiving the alarm signal, the driller 26 is required to respond,via the HMI 28, with a confirmation signal confirming that drill stringpressure integrity is in place. Once there is a positive indicator of aninflux, and the driller 26 has confirmed that the drill string pressureintegrity is in place, the control system 12 initiates an initial wellcontrol protocol by outputting a number of command signals to theinstallation and well control equipment, generally and collectivelyreferred to at 102, of the oil and gas installation 10.

In the illustrated system shown in FIG. 12, the initial well controlprotocol takes the form of a well shut-in procedure involving:communicating a drawworks command signal 62 to controller 64 of blow outpreventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-inthe wellbore 12. The controller 64 controls the BOP 66. It will berecognised that in other instances, for example in traditional rigs, theBOP 66 may be directly controlled rather than via a controller 64.

Beneficially, while the driller 26 is performing the manual operation ofmaking the connection, the control system 12 is operable to detect andreact to an influx that occurs during any one of the sub-phases ofmaking a connection.

FIG. 13 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,the control system 12 configured to detect and react to an influx duringa tripping operation, that is pulling the drillstring from the wellbore18 and/or running the drill string back into the wellbore 18, forexample to replace a drill bit.

As shown in FIG. 13, the control system 12 is connected to a levelsensor 104 in trip tank 106 of the oil and/or gas installation 10, thelevel sensor 104 configured to provide accurate real time dataindicative of the fluid level in the trip tank 106. The control system12 is also connected to drill bit depth sensor 108, the drill bit depthsensor 108 configured to provide real time data indicative of the depthof the drillstring in the wellbore 18.

The control system 12 is configured to determine, from the data providedby the drill bit depth sensor 108, the volumetric displacement of thedrill pipe as it trips into and/or out of the wellbore 18.

The control system 12 is configured to compare the data from levelsensor 104 relating to the fluid level in the trip tank 106 with thevolumetric displacement of the drill pipe determined from drill bitdepth sensor 108; a deviation in the form of an increase in the fluidlevel in the trip tank 106 relative to the determined volumetricdisplacement being indicative of an influx.

In the event a small deviation is detected by the control system 12, thecontrol system 12 is configured to relay a warning signal to the driller26 via the HMI 28. In the illustrated system, the warning signal takesthe form of an audible alarm signal. However, it will be understood thatthe warning signal may take any other suitable form, such as a visualand/or haptic signal or the like.

In the event of a larger deviation exceeding a preselected threshold setby the driller 26 when setting up and enabling the control system 12 atHMI 28, the control system 12 is configured to relay an alarm signal(different from the warning alarm) to the driller 26 via the HMI 28. Inthe illustrated system, the alarm signal comprises audible and visualalarm signals. However, it will be understood that the alarm signal maytake any other suitable form, such as a visual and/or haptic signal orthe like.

On receiving the alarm signal, the driller 26 is required to respond,via the HMI 28, with a confirmation signal confirming that drill stringpressure integrity is in place.

Once there is a positive indicator of an influx, and the driller 26 hasconfirmed that the drill string pressure integrity is in place, thecontrol system 12 initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment, generally and collectively referred to at 102, of theoil and gas installation 10.

In the illustrated system, the initial well control protocol takes theform of a well shut-in procedure involving: communicating a drawworkscommand signal 62 to controller 64 of blow out preventer (BOP) 66 toinstruct the BOP 66 to close and thereby shut-in the wellbore 12.

The controller 64 controls the BOP 66. It will be recognised that inother instances, for example in traditional installations, the BOP 66may be directly controlled rather than via controller 64.

On receiving the audible alarm and/or visual warning, the driller 26 isrequired to respond, via the HMI 28, with a confirmation signalconfirming that drill string pressure integrity is in place before thewell shut-in operation is initiated.

Beneficially, the control system 12 is configured to detect and react toan influx that occurs during a tripping operation, such as tripping in,tripping out, pulling wet, pulling dry, and with or without a float inthe drillstring.

FIG. 14 of the accompanying drawings shows an alternative systemtopology of the control system 12 for detecting and reacting to aninflux during a tripping operation to that shown in FIG. 13.

As shown in FIG. 14, in addition to being connected to the level sensor104 and the drill bit depth sensor 108, the control system 12 is alsoconnected to a flow rate sensor 110, thereby permitting the controlsystem 12 to monitor the fluid flow rate from the wellbore 18. The flowrate sensor 110 may be identical or similar to the sensor 32 or flowline flow rate sensor 100 described above, or may take the form ofanother flow rate sensor.

Beneficially, the addition of fluid flow rate data from flow rate sensor110 permits the control system 12 to take account of how the mudflowrate effect of tripping in and tripping out of the wellbore 18 wouldadd or subtract to a potential influx flow rate.

As described above, following initiation of the initial well controlprotocol, the system 12 may be configured to action a further wellcontrol protocol in the form of an influx circulation operation.

FIG. 15 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,the control system 12 configured to perform an influx circulationoperation, that is flowing the influx fluid out of the wellbore 18.

For clarity, the components required to detect and react to an influxand initiate the initial well control protocol have been omitted.

As shown in FIG. 15, the control system 12 is connected to sensors,shown collectively at 112, configured to monitor drill pipe pressure,casing pressure, mud pump speed, mud pump strokes, and choke position.

The control system 12 is configured to calculate the requiredinformation to perform the circulation operation such as kill-weight,mud weight, initial circulating pressure (ICP), and slow circulatingrates (SCR).

In use, when an influx has been shut-in, and the installation 10 isready to circulate out the influx, the control system 12 automaticallytakes control of the mud pumps 60 and the choke 68 to perform the influxcirculation operation or operations, as required, whilst maintaining thehydrostatic pressure above the pore pressure by the required overbalancemargin, and maintaining that overbalance steady, throughout thecirculation operation(s).

Beneficially, the system is configured to cater for all types of commonwell kill methodologies, including the Drillers' Method and/or the Waitand Weight Method known in the art.

Moreover, the control system 12 is configured to identify problematicissues during well kill operations, such as plugged nozzles, plug choke,washed choked, washed drill pipe, or the like. On identification of suchissues, the control system 12 is configured to stop operations and relaya warning signal to the driller 26 via the HMI 28, together with therecommended corrective procedure. The driller 26 will be required toaccept, via the HMI 28, the recommended solution before the controlsystem completes the well kill operation.

At any time, the HMI 28 is adaptable to display a range of displays interms of pressure, time, and strokes pumps or the like.

FIG. 16 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,in this instance a managed pressure drilling (MPD) system 114 of the oiland/or gas installation 10.

As shown in FIG. 16, the control system 12 is connected to the MPDsystem 114, the control system 12 configured to receive a signal fromthe MPD system 114 indicating that an influx may have been detected.

The control system 12 is configured to check the signal from the MPDsystem 114 and determine from the received signal whether or not thepreselected threshold has been exceeded.

On determining that the preselected threshold has been exceeded, thecontrol system 12 is configured to generate one or more output signal inthe form of an alarm signal on the HMI 28 in the control station 22.

The control system 12 also initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment 102 of the oil and gas installation 10.

In the illustrated system shown in FIG. 16, the initial well controlprotocol takes the form of a well shut-in procedure involving:communicating a command signal 42 to controller 44 of drawworks 46 toinstruct the drawworks 46 to raise the drill string 48 off the bottom ofthe wellbore 18; communicating a command signal 50 to controller 52 oftop-drive 54 to instruct the top drive 54 to stop rotating;communicating a command signal 56 to controller 58 of mud pumps 60 toinstruct the mud pumps 60 to stop pumping fluid into the wellbore 18;and communicating a command signal 62 to controller 64 of blow outpreventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-inthe wellbore 12. The controllers 44, 52, 58, and 64 each controlcomponents 46,54,60 and 66 respectively. It will be recognised that inother instances, for example in traditional installations, thecomponents may be directly controlled rather than via controllers.

Prior to initiation of the shut-in, the control system 12 will look forfurther confirmation checks from the MPD system 114 that such an actionis still valid. Beneficially, the control system 12 facilitatesautomated well control systems and operations to be combined withpre-existing MPD systems on an oil and/or gas installations. Moreover,the control system 12 is operable such that if the volume of an influxis greater than the maximum influx that the MPD system 114 can circulateout (nominally 5 bbls), the control system 12 facilitates at least theinitial shut-in of the well quickly, efficiently and with minimal or nohuman intervention.

FIG. 17 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,in this instance an early kick detection system (EKDS) 116. In theillustrated system shown in FIG. 17, the EKDS 116 is a pre-existingthird party EKDS 116 of the oil and/or gas installation 10.

As shown in FIG. 17, the control system 12 is connected to the EKDS 116,the control system 12 configured to receive a signal from the EKDS 116indicating that an influx may have been detected.

The control system 12 is configured to check the signal from the EKDS116 and determine from the received signal whether or not thepreselected threshold has been exceeded.

On determining that the preselected threshold has been exceeded, thecontrol system 12 is configured to generate one or more output signal inthe form of an alarm signal on the HMI 28 in the control station 22.

The control system 12 also initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment 102 of the oil and gas installation 10.

In the illustrated system shown in FIG. 17, the initial well controlprotocol takes the form of a well shut-in procedure involving:communicating a command signal 42 to controller 44 of drawworks 46 toinstruct the drawworks 46 to raise the drill string 48 off the bottom ofthe wellbore 18; communicating a command signal 50 to controller 52 oftop-drive 54 to instruct the top drive 54 to stop rotating;communicating a command signal 56 to controller 58 of mud pumps 60 toinstruct the mud pumps 60 to stop pumping fluid into the wellbore 18;and communicating a command signal 62 to controller 64 of blow outpreventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-inthe wellbore 12. The controllers 44, 52, 58, and 64 each controlcomponents 46,54,60 and 66 respectively. It will be recognised that inother instances, for example in traditional installations, thecomponents may be directly controlled rather than via controllers.

Prior to initiation of the shut-in, the control system 12 will look forfurther confirmation checks from the EKDS 116 that such an action isstill valid.

FIG. 18 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,in this instance an early kick detection system (EKDS) 118.

As shown in FIG. 18, the control system 12 is connected to the EKDS 118,the control system 12 configured to receive a signal from the EKDS 118indicating that an influx may have been detected.

Referring now also to FIG. 19 of the accompanying drawings, the EKDS 118is connected to and configured to receive sensor data from a sensorarrangement, generally designated 120, including one or more of: a flowline flow rate sensor 122; a pit volume totalizer (PVT) sensor 124; arate of penetration (ROP) sensor 126; a mud pump speed (strokes perminute or SPM) sensor 128; a mud pump pressure (MPP) sensor 130; a drillstring weight (DSVV) sensor 132; a mudflow sensor 134; a connection gassensor 136; a movement sensor 138; and a mud property (mud weight,plastic viscosity) sensor 140.

As shown in FIG. 18, the EKDS 118 is connected to the control system 12and HMI 28 and the configured so that the configuration of the sensorarrangement 120 can be adjusted by the driller 26 via the HMI 28.

The EKDS 118 comprises control software configured to receive, compute,process and combine the sensor data from the sensor arrangement 120, theresultant information then being tested against pre-set criteria (of avoting/delegation form) set by the operator. If the received andprocessed sensor information satisfies the pre-set criteria, then thesignal will be relayed from the EKDS 118 to the control system 12 toinitiate the command sequence to begin the initial well controlprotocol.

Prior to initiation of the shut-in, the control system 12 will look forfurther confirmation checks from the EKDS 118 that such an action isstill valid.

As described above, the sensor arrangement 120 comprises one or moreflow line flow rate sensor 122, the flow rate sensor 122 configured tomeasure flow rate from the wellbore 18. The flow rate sensor 122 may beidentical or similar to the sensor 32, flow line flow rate sensor 100 orflow rate sensor 110 described above, or may take the form of anotherflow rate sensor.

The sensor arrangement 120 in the illustrated system comprises aplurality of PVT sensors 124 placed around the active mud pit andconfigured to measure changes in the active mud pit fluid level, thisbeing a primary kick indicator.

As regards the PVT sensors 124, the EKDS 118 is configured to processthe information obtained from the (active) PVT sensors 124 to compute anaverage fluid level height at a given time: i) whilst drilling ahead;and ii) during connections but only after fluid flow back of the flowline. The average fluid level would need to be compared with previousreadings (e.g. every 15 secs) and also for trending changes. Data shouldbe excluded for a short period during the start up and/or stopping ofthe mud pumps 60 and/or for intentional changes in the speed of the mudpumps 60 instructed by the driller 26.

As described above, the sensor arrangement 120 comprises one or more ROPsensor 126, the ROP sensor 126 configured to detect an instantaneousincrease in the rate of penetration of the drillstring, this being asecondary kick indicator.

The ROP sensor 126 uses information from the drawworks encoder sensor(that effectively measures the block height and thus the rate at whichthe drill pipe goes into the well). Alternatively or additionally, theROP sensor 126 may take the information from other height measurementsources.

As regards the ROP sensor 126, the EKDS 118 is configured to process theinformation from the ROP sensor 126 by comparing the current ROP withthe recorded average and instantaneous ROP values over a selecteddistance, e.g. the last 100 ft drilled.

As described above, the sensor arrangement 120 comprises one or more SPMsensor 128, the SPM sensor 128 configured to detect an increase in mudpump strokes per minute (SPM), this being another secondary kickindicator. The SPM sensor 128 uses information from the active mud pumpspeed controller/measurement device.

As regards the SPM sensor 128, the EKDS 118 is configured to process theinformation obtained by the SPM sensor 128 by compare the current totalmud pumps' strokes per minute with the recorded average andinstantaneous strokes per minute over a selected past time period, e.g.the previous 5 minutes.

As described above, the sensor arrangement 120 comprises one or more mudpump pressure (MPP) sensor 130, the MPP sensor 130 configured to detecta decrease in mud pump pressure (MPP), this being another secondary kickindicator. The MPP sensor 130 uses information from the mud pumppressure output measurement device.

As regards the MPP sensor 130, the EKDS 118 is configured to process theinformation obtained by the MPP sensor 130 by comparing the current mudpump pressure with the recorded average and instantaneous mud pumppressures over a selected past time period, e.g. the previous 5 minutes.

As described above, the sensor arrangement 120 comprises a drill stringweight (DSVV) sensor 132, the DSW sensor 132 configured to detect asudden change (in particular an increase in weight/reduction inbuoyancy) in drill string weight (DSVV), this being a secondary kickindicator. The DSW sensor 132 uses information from the drillstringweight indicator.

As regards the DSW sensor 132, the EKDS 118 is configured to process theinformation obtained by the DSW sensor 132 by comparing the current DSWwith the recorded average and instantaneous drill string weights over aselected time period, e.g. the previous 5 minutes.

As described above, the sensor arrangement 120 comprises a mud pumpmudflow sensor 134, the mud pump mudflow sensor 134 configured tomeasure the mud pump flow rate.

In the illustrated system, the mud pump mudflow sensor 134 comprises aCoriolis type flowmeter on the input to each mud pump 60 and a Coriolistype flowmeter in the flow line.

Alternatively, flowrate information may be determined by taking theinput and output flowrate information feeds from the stroke counters.

As regards the mud pump mudflow sensor 134, the EKDS 118 is configuredto process the information obtained by comparing the instantaneous totalflowrate going into the wellbore 18 (by combining mud pump inputCoriolis flowrate) with the instantaneous exit flowrate coming out ofthe wellbore 18.

As described above, the sensor arrangement 120 comprises a connectiongas sensor 136 comprising online instrumentation configured to measurethe size of each gas peak associated with each successive connection.

As regards the connection gas sensor 136, the EKDS 118 is configured toprocess the information obtained by the connection gas sensor 136 bycomparing the size and/or position of each gas peak with that of theprevious gas peak. An increasing trend, subject to pre-set criteria,could indicate a kick, and the EKDS 118 will process this information,along with information from other module sensors.

As described above, the illustrated oil and/or gas installation 10comprises a floating platform 14 and the sensor arrangement 120comprises or is operatively associated with one or more movement sensor138 configured to measure movement of the platform 14 in terms of heave,sway, surge, roll, pitch and yaw.

As regards the movement sensor 138, the EKDS 118 is configured toreceive and process the information from the movement sensor 138.Movement of the platform 14 is measured: i) using movement sensors; ii)using the motion reference unit (MRU) on the platform 14 and/or iii)predicted based upon expected Response Amplitude Operator (RAO) valuesbased upon the given weather and sea states.

The resultant movement information will then be used to predict theeffect of the movement of the platform 14 on the flowrate in the flowline and/or the active pit fluid level. This prediction takes intoeffect fluid movement lag times and the design of fluid flow lines,circulation paths, and fluid pits on the installation, and the actualongoing operations on the installation (e.g. drilling ahead, tripping,connections) at the time. The overall predicted fluid flowrate and fluidlevel characteristics will then be compared with the instantaneousreadings on the platform 14. Comparisons will be made in terms ofabsolute values at a given time, and in terms of trending values.Deviations will be compared against predicted information on a pre-setcriteria basis.

As described above, the sensor arrangement 120 comprises one or more mudproperty sensor 140. The EKDS 118 and/or control system 12 is configuredto take the automated mud measurements from an automated mud parametermeasurement device 140, and run a series of algorithms looking at mudweights, gas cut percentages, salts, oil and water phases etc. then, asrequired, activate the initial well control protocol. Sensor modules(individually)

Each of the EKDS 118 and the sensors122,124,126,128,130,132,134,136,138, 140 of the sensor arrangement 120above can be provided as a separate module implemented in software.

FIG. 20 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,the control system 12 configured to detect and react to an influx duringnormal circulating activities.

As shown in FIG. 20, the control system 12 is connected to a flowmeter142 and is configured to receive real time sensor data from the sensor142, thereby permitting the control system 12 to monitor the fluid flowrate from the wellbore 18 during circulation. The sensor 142 may beidentical to the sensor 32 described above, or may take the form ofanother flow rate sensor. The control system 12 is also connected to amud pump speed sensor 144 configured to measure the speed of the mudpumps 60.

The control system 12 is configured so that the base level flowrate heldby control system 12 is adaptable to, typically frequent, alterations tothe mud pump speed/flowrate made by the driller 26.

The incremental flowrate that triggers the initial well control protocolis inputted as a percentage increase. However, it will be understoodthat the incremental flowrate that triggers the initial well controlprotocol may alternatively be inputting as a fixed incremental amountabove the instantaneous flowrate.

In the illustrated system shown in FIG. 20, the initial well controlprotocol takes the form of a well shut-in procedure involving:communicating a command signal 42 to controller 44 of drawworks 46 toinstruct the drawworks 46 to space out; communicating a command signal50 to controller 52 of top-drive 54 to instruct the top drive 54 to stoprotating; communicating a command signal 56 to controller 58 of mudpumps 60 to instruct the mud pumps 60 to stop pumping fluid into thewellbore 18; and communicating a command signal 62 to controller 64 ofblow out preventer (BOP) 66 to instruct the BOP 66 to close and therebyshut-in the wellbore 12. The controllers 44, 52, 58, and 64 each controlcomponents 46,54,60 and 66 respectively. It will be recognised that inother instances, for example in traditional installations, thecomponents may be directly controlled rather than via controllers.

However, the driller 26 can pre-select whether or not the space-out isrequired.

If de-selected, then the control system 12 defaults to the annular BOPas the BOP to close.

FIG. 21 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,the control system 12 configured to monitor the well when static.

As shown in FIG. 21, the control system 12 is connected to a levelsensor 146 configured to measure fluid level in the trip tank 106, aflow line sensor 148 configured to measure fluid flow rate, and a sensor150 configured to measure the active pit volume. In the illustratedsystem, during initial set up the driller 26 preselects, via the HMI 28,which of the sensors 146,148,150 are monitored. The decision as to whichof the sensors 146, 148,150 are monitored may depend on whether theoperation is being carried out in open hole or cased hole and/or how themud flow system is lined up.

The control system 12 is configured to determine from the sensor datareceived from the selected sensors 146,148,150, whether a detectedvolume change in the trip tank and/or in the active pit, or a detectedflowrate change in the flow line exceeds a preselected threshold set bythe driller 26 when setting up and enabling the control system 12 at theHMI 28, this being indicative of a fluid influx condition in thewellbore 12.

On determining that the fluid flow rate does exceed the preselectedthreshold fluid flow rate, the control system 12 is configured togenerate one or more output signal in the form of an alarm signal on theHMI 28 in the control station 22. In the illustrated system, the alarmsignal comprises audible and visual alarm signals.

The control system 12 initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment 102.

In the illustrated system shown in FIG. 21, the initial well controlprotocol takes the form of a well shut-in procedure involving:communicating a command signal 42 to controller 44 of drawworks 46 toinstruct the drawworks 46 to space out; communicating a command signal50 to controller 52 of top-drive 54 to instruct the top drive 54 to stoprotating; communicating a command signal 56 to controller 58 of mudpumps 60 to instruct the mud pumps 60 to stop pumping fluid into thewellbore 18; and communicating a command signal 62 to controller 64 ofblow out preventer (BOP) 66 to instruct the BOP 66 to close and therebyshut-in the wellbore 12. The controllers 44, 52, 58, and 64 each controlcomponents 46,54,60 and 66 respectively. It will be recognised that inother instances, for example in traditional installations, thecomponents may be directly controlled rather than via controllers.

However, the driller 26 can pre-select whether or not the space-out isrequired. If de-selected, then the control system 12 defaults to theannular BOP as the BOP to close.

FIG. 22 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,the control system 12 configured to monitor the well when static.

As shown in FIG. 22, the control system 12 is connected to a levelsensor 152 configured to measure fluid level in the trip tank 106.

The control system 12 is configured to determine from the sensor datareceived from the sensors 152, whether a detected volume change in thetrip tank exceeds a preselected threshold set by the driller 26 whensetting up and enabling the control system 12 at the HMI 28, this beingindicative of a fluid influx condition in the wellbore 12.

On determining that the detected volume change does exceed thepreselected threshold fluid flow rate, the control system 12 isconfigured to generate one or more output signal in the form of an alarmsignal on the HMI 28 in the control station 22. In the illustratedsystem, the alarm signal comprises audible and visual alarm signals. Thecontrol system 12 initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment 102.

In the illustrated system shown in FIG. 22, the initial well controlprotocol takes the form of a well shut-in procedure involving:communicating a drawworks command signal 62 to controller 64 of blow outpreventer (BOP) 66 to instruct the BOP 66 to close and thereby shut-inthe wellbore 12. The controller 64 controls the BOP 66. It will berecognised that in other instances, for example in traditional rigs, theBOP 66 may be directly controlled rather than via controller 64.

Beneficially, the control system 12 can be utilised to monitor inflowtests on liner packers or on certain lower completions.

As described above, following initiation of the initial well controlprotocol the control system 12 may be configured to initiate a furtherwell control protocol in the form of a fluid pumping operation.

FIG. 23 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,the control system 12 configured to monitor the well during such a fluidpumping operation.

As shown in FIG. 23, the control system 12 is connected to a sensorarrangement, generally denoted 154, comprising one or more flow ratesensor, casing pressure gauge, mud pump speed and pressure sensors, mudproperty sensor. The control system 12 also receives leak-off test dataand drill bit depth data.

Beneficially, the control system 12 is configured to limit the influxsize that is shut-in by turning off the mud pump(s) 60 slowly ratherthan with the normal turn on/off approach. This means that the loss ofhydrostatic pressure due to the mud pump(s) 60 being turned off (i.e.loss of the equivalent circulating density (ECD) occurs more slowly,thus limiting the size of influx coming into the wellbore 18 andallowing pressures to equalise more quickly in the wellbore 18 aftershutting in.

The control system 12 is configured to ensure that the Leak Off Testvalue (LOT) at the previous casing shoe will not be exceeded.

FIG. 24 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 24, the control system 12 is connected to a sensorarrangement, generally denoted 156, comprising one or more flow ratesensor, casing pressure gauge, mud pump speed and pressure sensors, mudproperty sensor. The control system 12 also receives drill bit depthdata.

Beneficially, the control system 12 addresses a problem that isrelatively common in clastic formations and in High Pressure HighTemperature (HPHT) wells, called Ballooning, whereby the dynamic mudweight pressure approaches the formation pressure resulting of smallamounts of drilling fluid leaking into the formation. On a connection,when the mud pumps 60 are turned off and the drilling fluid pressurereduces, the leaked fluid will flow back into the wellbore 18. This canbe a substantial volume over a long open hole section. It can bedifficult to decipher this flow back from a true influx. The flow backwill give a signature “flowrate with time” at surface.

During normal drilling operations, the control system 21 measures everysignature on every connection, the control system 12 determining fromthe data received from the sensor arrangement 156 and optionallyutilising an Artificial Intelligence algorithm, an expected signature atthe next connection, the expected signature taking into account theextra amount of ballooning-prone formation now exposed.

The control system 12 compares the actual flow back signature at surfacewith the predicted signature, and subject to certain pre-set criteria,will action the initial well control protocol to shut in the well.

This module could be connected to the EKDS 118, or could be a standalonemodule.

FIG. 25 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,the control system 12 configured to detect and react to an influx duringa swabbing operation.

As shown in FIG. 25, the control system 12 is connected to a sensorarrangement, generally denoted 158, comprising one or more mud propertysensor. The control system 12 also receives wellbore dimension data,drill bit depth data and leak-off test data.

The control system 12 is configured to calculate the maximum pull out ofhole (POOH) speed on a continuous basis.

In the event an influx is detected, the control system 12 is configuredto generate one or more output signal in the form of an alarm signal onthe HMI 28 in the control station 22. In the illustrated system, thealarm signal comprises audible and visual alarm signals. The controlsystem 12 initiates an initial well control protocol by outputting anumber of command signals to the installation and well control equipment102 to shut in the wellbore 18.

Beneficially, the control system 12 permits the POOH speed to bemaximised while avoiding or at least mitigating the risk of swabbing aninflux into the wellbore 18.

FIG. 26 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,the control system 12 configured to detect and react to an influx duringa run-in operation.

As shown in FIG. 26, the control system 12 is connected to a sensorarrangement, generally denoted 160, comprising one or more mud propertysensor. The control system 12 also receives wellbore dimension data,drill bit depth data and leak-off test data.

Surging is when the bottom hole pressure is increased due to the effectsof running the drill string too fast in the wellbore 18. Downhole mudlosses may occur if care is not taken and fracture pressure is exceededwhile running in hole (RIH).

The control system 12 is configured to calculate the maximum RIH speedon a continuous basis.

In the event an influx is detected, the control system 12 is configuredto generate one or more output signal in the form of an alarm signal onthe HMI 28 in the control station 22. In the illustrated system, thealarm signal comprises audible and visual alarm signals. The controlsystem 12 initiates an initial well control protocol by outputting anumber of command signals to the installation and well control equipment102 to shut in the wellbore 18.

FIG. 27 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,the control system 12 configured to detect and react to an influx duringa run-in operation.

As shown in FIG. 27, the control system 12 is connected to a sensorarrangement, generally denoted 162, comprising one or more mud property,flowrate, speed and pressure sensors. The control system 12 alsoreceives wellbore dimension data, casing depth data and leak-off testdata.

The control system 12 is configured to determine from the received datawhether an influx is occurring. In the event an influx is detected, thecontrol system 12 is configured to generate one or more output signal inthe form of an alarm signal on the HMI 28 in the control station 22. Inthe illustrated system, the alarm signal comprises audible and visualalarm signals. The control system 12 initiates an initial well controlprotocol by outputting a number of command signals to the installationand well control equipment 102 to shut in the wellbore 18.

Beneficially, the control system 12 detects and reacts to an influxduring the running of casing or liners.

FIG. 28 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 28, the control system 12 is connected to a sensorarrangement, generally denoted 164, comprising one or more mud property,flowrate, speed and pressure sensors. The control system 12 alsoreceives wellbore dimension data, completion depth data and leak-offtest data.

The control system 12 is configured to determine from the received datawhether an influx is occurring.

In the event an influx is detected, the control system 12 is configuredto generate one or more output signal in the form of an alarm signal onthe HMI 28 in the control station 22. In the illustrated system, thealarm signal comprises audible and visual alarm signals.

The control system 12 initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment 102 to shut in the wellbore 18.

Beneficially, the control system 12 detects and reacts to an influxduring the running of completions.

FIG. 29 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 29, the control system 12 is connected to a sensorarrangement, generally denoted 166, comprising one or more mud property,flowrate, speed and pressure sensors. The control system 12 alsoreceives wellbore dimension data, casing depth data and leak-off testdata.

The control system 12 is configured to determine from the received datawhether an influx is occurring.

In the event an influx is detected, the control system 12 is configuredto generate one or more output signal in the form of an alarm signal onthe HMI 28 in the control station 22. In the illustrated system, thealarm signal comprises audible and visual alarm signals.

The control system 12 initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment 102 to shut in the wellbore 18.

Beneficially, the control system 12 detects and reacts to an influxduring the cementing of casing or liner.

FIG. 30 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 30, the control system 12 is connected to a sensorarrangement, generally denoted 168, comprising one or more mud property,flowrate, speed and pressure sensors. The control system 12 alsoreceives flowrate (with or without riser) data, and wind direction data.

The control system 12 is configured to determine from the received datawhether an influx is occurring.

In the event an influx is detected, the control system 12 is configuredto generate one or more output signal in the form of an alarm signal onthe HMI 28 in the control station 22. In the illustrated system, thealarm signal comprises audible and visual alarm signals.

The control system 12 initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment 102 to divert the flow from the well to a safe area.

The control system 12 is designed for drilling the upper sections of thewellbore 18 which are drilled without the BOP, and where it would nothave been safe to shut in the well due to the risk of casing shoefracture. If the drilling encounters a pocket of shallow gas, thecontrol system 12 will detect the high mud flowrate return out of thewell annulus. The methodology to detect the flowrate will be determinedby the drilling mode; i.e. whether or not a riser is in place.

The control system 12 will relay an alarm signal to the driller 26 viathe HMI 28.

The control system will continually pre-assess wind direction at alltimes, and following the alarm signal, would then send a signal to openthe downwind overboard line valve. A signal would then be sent to closethe diverter, and thus divert the flow away from the installation 10.The system will then initiate a shallow gas protocol, including forexample automated pumping of higher density drilling fluid.

FIG. 31 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 31, the control system 12 is connected to a sensorarrangement, generally denoted 170, comprising trip tank pump and levelsensors.

For installations without a riser gas handling system, once BOPs areactivated by the control system 12, the control system 12 willautomatically switch on the Trip Tank (TT) pump and switch the surfacevalves to monitor the riser contents.

The control system 12 will monitor the trip tank 106. If the trip tank106 level increases, over a period of time, the BOP has either notclosed properly, or there is migrating gas in the riser, or both.

In either case, the control system 12 will close another BOP and willconsider directing the flow to the poor boy degasser (PBD) or operatethe diverter system (having also assessed wind direction).

The consideration of routing will take account of the capacity of thePBD both from the vessel throughput aspect and from a U-tube aspect.

If either of these are exceeded, then the control system 12 willinstruct to divert the flow through the diverter.

FIG. 32 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 32, the control system 12 is connected to a sensorarrangement, generally denoted 170, comprising trip tank pump and levelsensors.

For installations with a riser gas handling system, once the BOPs areactivated by the control system 12, the control system 12 willautomatically switch on the Trip Tank (TT) pump and switch the surfacevalves to monitor the riser contents.

The control system 12 will monitor the trip tank.

If the trip tank level increases, over a period of time, the BOP haseither not closed properly, or there is migrating gas in the riser, orboth.

In either case, the control system 12 will initiate an increase inclosing pressure on the BOP and/or close another BOP and/orautomatically function the riser gas annular simultaneously.

FIG. 33 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 33, the control system 12 is connected to BOP sensors174.

The control system 12 is configured to detect the pressure below aclosed BOP, and then execute an interlock to prevent any party fromopening the BOP.

FIG. 34 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 34, the control system 12 is connected to a library,generally denoted 176, of operator and/or drilling contractor wellcontrol procedures for tripping, connections drilling etc.

Beneficially, the link to the library 176 permits the sequencing of thecontrol system 12 operations to be tailored to to given operator and/ordrilling contractor's well control procedures.

FIG. 35 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 35, the control system 12 is connected to a multi-rigsensor arrangement, generally denoted 178.

The control system 12 is configured to determine, using the data fromthe multi-rig sensor arrangement 178, the particular phase of wellconstruction at a given time, and then automatically ensure that theappropriate control system 12 module is in operation for that phase.

Beneficially, this permits the control system 12 to be on at all times.

FIG. 36 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 36, the control system 12 is configured to receivetidal data, selected space-out position data and time linking data,generally denoted 180.

The control system 12 is configured, based on the data 180, toautomatically adjust the space-out position in response to changes intide and select another BOP such as the annular.

In use, the driller 26 would select the space out positions on thecontrol system 12 via the HMI 28 at initial set-up. Those positionswould be logged as would be the time at which they were logged. Wherecertain changes of tide make a previously selected space-out positionunusable, the control system 12 relays an alter signal to the drill 26requesting a updated set of space-out positions.

Beneficially, the system is particularly adapted for use on a floatingrig that is subject to a large tidal range.

FIG. 37 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 37, the control system 12 is configured to receive BOPdimension data, tidal data, space-out position data and BOP preferenceinformation, generally denoted 182.

The control system 12 is configured, based on the data 182, toautomatically assess the position of the tool joint in relation to theexact BOP configuration on the installation, and to then auto-selectwhich is the best BOP to close at any given time.

FIG. 38 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 38, the control system 12 is configured to receivewireline depth meter data, rig floor depth data and safety distancedata, generally denoted 184.

In use, the control system 12 is configured, based on the data 184, torelay an alert signal to the driller 26, via the HMI 28, and/or wirelinesupervisor via a suitable data link, when pulling out of hole indicatingthat the tooling is near/at surface or is becoming held up and/or whenrunning in hole that is close to target depth, or if it become held up.

Beneficially, the system provides an automated warning for control ofslickline, wireline, coil tubing etc.

FIG. 39 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,during coiled tubing operations.

As shown in FIG. 39, the control system 12 is connected to a flowratesensor 186, the sensor 186 associated with the coiled tubing system ofthe installation 10.

In the event an influx is detected during coiled tubing operations, thecontrol system 12 is configured to generate one or more output signal inthe form of an alarm signal on the HMI 28 in the control station 22. Inthe illustrated system, the alarm signal comprises audible and visualalarm signals.

The control system 12 also initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment 102, in this instance including the BOP operativelyassociated with the coiled tubing, to shut in the wellbore 18.

FIG. 40 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10,during wireline operations.

As shown in FIG. 40, the control system 12 is connected to a flowratesensor 188, the sensor 188 associated with the wireline system of theinstallation 10.

In the event an influx is detected during wireline operations, thecontrol system 12 is configured to generate one or more output signal inthe form of an alarm signal on the HMI 28 in the control station 22. Inthe illustrated system, the alarm signal comprises audible and visualalarm signals.

The control system 12 also initiates an initial well control protocol byoutputting a number of command signals to the installation and wellcontrol equipment 102, in this instance including the BOP operativelyassociated with the wireline, to shut in the wellbore 18.

FIG. 41 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 41, the control system 12 is configured to receive GPSand/or other positioning system data and vessel propulsion control data,generally denoted 190. The control system 12 is configured, based on thereceived data 190, to output a number of command signals to theinstallation and well control equipment 102 to close blind/shear,disconnect the Lower Marine Riser Package (LMRP), and performinstallation drive off.

FIG. 42 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 42, the control system 12 is configured to receive GPSand/or other positioning system data and vessel propulsion control data,and gas sensor data, generally denoted 192.

The control system 12 is configured, based on the received data 192, tooutput a number of command signals to the installation and well controlequipment 102 to close the blind/shear, disconnect the Lower MarineRiser Package (LMRP), and drive off.

FIG. 43 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 43, the control system 12 is configured to receive GPSand/or other positioning system data and vessel propulsion control data,and excursion limit pre-integrity failure data, generally denoted 194.

The control system 12 is configured, based on the received data 194, tooutput a number of command signals to the installation and well controlequipment 102 to close the blind/shear, disconnect the Lower MarineRiser Package (LMRP), and perform a drive off.

Beneficially, the control system 12 is configured to shut-in the wellwhere e.g. an excursion of the installation (e.g. due to a failedDynamic Positioning system) reaches a point where the integrity of theriser/BOP system would otherwise be compromised.

FIG. 44 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 44, the control system 12 is connected to a BOP sensorarrangement, generally denoted 196, the BOP sensor arrangement 196configured to receive data from the BOP 66.

The control system 12 is configured, based on the data 196, toautomatically and continually perform BOP fault finding and, in theevent of an influx, automatically initiate a required change (e.g. PodChange or next lower BOP activation) to make the BOP 66 function.

FIG. 45 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 45, the control system 12 is connected to a sensorarrangement, generally denoted 198, configured to receive data from allwell control equipment on the installation 10.

The control system 12 is configured to monitor the status/health of keywell control equipment (BOP, mud pumps, choke) and the associatedequipment instrumentation on the HMI 28, and relay an audible alarmand/or visual signal in the event of a discrepancy in performance beyonda selected threshold.

FIG. 46 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 46, the control system 12 is connected to a sensorarrangement, generally denoted 200, configured to receive flowmeterdata, trip tank sensor data, and active pit volume sensor data.

The control system 12 is configured to monitor the wellbore 18 during aplug drill out operation during well decommissioning.

This is particularly important where previously-installed downholebarriers may be of questionable nature, or where insufficient mud weightcannot be properly achieved prior to drilling out a plug with apotential high pressure below.

FIG. 47 of the accompanying drawings shows an alternative systemtopology of the control system 12, illustrating the integration of thecontrol system 12 with components of the oil and/or gas installation 10.

As shown in FIG. 47, the control system 12 is connected to a sensorarrangement, generally denoted 202, configured to receive flowmeterdata, trip tank sensor data, and active pit volume sensor data.

The control system 12 is configured to output command signals to amechanical arm, to be used for example to automatically install, torqueup, and close a full opening safety valve (FOSV).

Each of the system topologies described above with reference to FIGS. 12to 47 may be implemented within the control software of the controlsystem 12 or may be a standalone module.

Various modifications can be made without departing from the scope ofthe claimed invention.

For example, the control system 12 may comprise or may be operativelyassociated with a software module that can determine the health of aflow meter. The module, flowmeter paddle, and even the health of aCoriolis meter, or any other flow meter. For example, the control systemmay be configured to determine the health of a flow meter where, forexample: there are no fluctuations in flow rate detected over aspecified period; the flow meter outputs a minimum reading when mudpumps are operating well above that level; the flow meter outputs amaximum reading when the mud pumps are operating well below that level;and/or the flow meter outputs a significantly different reading topreviously observed recent readings.

The control system 12 may comprise or may be operatively associated witha software module that can record data critical to the decision toshut-in the well and will record all relevant instrumentation, actionsand timing throughout the process of automatically safely shutting inthe well to provide historical record for future analysis of theeffectiveness of the system responses, and any human interventions.

The control system 12 may pass data in real time over a secure internetlink enabling management to view status of control system at any time.This will also provide all data critical to the decision to shut-in thewell ensuring a safe remote record all relevant instrumentation, actionsand timing throughout the process of automatically safely shutting inthe well to provide historical record for future (and immediate)analysis of the effectiveness of the system responses, and any humaninterventions.

The control system 12 program may be accessible over a secure internetlink enabling technical support for fault finding diagnostics,configuration & upgrades to be affected from Safe Influx office or otherremote location. This will provide enhanced efficiency of commissioningand support to ensure maximum up-time for the control system 12equipment, and reduce the need for high skilled technical support inremote locations.

The control system 12 may comprise or may be operatively associated witha biometric security software module. The biometric security module isused where pre-operation or post-operation authorisation is required(e.g. opening of a closed BOP). The biometric security module requirese.g. thumb-print, or face recognition identification of higher authority(e.g. a toolpusher), on the HMI 28.

The control system 12 may be configured to allow the driller 26 theability to shut-in the wellbore 18 without having to switch the controlsystem 12 off, e.g. in an emergency situation. There would be a buttonon the HMI 28, that would enable a one or two touch action to performthe full shut in sequence including space out, stop drilling equipmentand close the BOP 66.

1. An automated system for use in well control, the system comprising: acontroller configured to receive an input signal indicative of a fluidflow rate or fluid volumetric rate from a wellbore, the controllerconfigured to determine from said input signal whether the fluid flowrate or fluid volumetric rate exceeds a preselected threshold indicativeof a fluid influx condition in the wellbore system, wherein, ondetermining that said fluid flow rate or fluid volumetric rate exceedssaid preselected threshold, the controller is configured toautomatically output one or more command signals initiating an initialwell control protocol.
 2. The system of claim 1, wherein the initialwell control protocol comprises a well shut-in protocol.
 3. The systemof claim 12, wherein the initial well control protocol comprises one ormore preselected well control operations.
 4. The system of claim 3,wherein the initial well control protocol comprises a plurality of wellcontrol operations.
 5. The system of claim 1, wherein the system isconfigured for coupling to, to communicate with or may be operativelyassociated with components of an oil and/or gas installation.
 6. Thesystem of claim 5, wherein the system is configured for coupling to, tocommunicate with or may be operatively associated with a drawworks ofthe installation, the initial well control protocol comprising a commandsignal to the drawworks to raise the drill string off the bottom of thewellbore.
 7. The system of claim 5, wherein the system is configured forcoupling to, to communicate with or may be operatively associated with atop drive of the installation, the initial well control protocolcomprising a command signal to the top drive to stop rotation of the topdrive.
 8. The system of claim 5, wherein the system is configured forcoupling to, to communicate with or may be operatively associated withone or more mud pumps of the installation, the initial well controlprotocol comprising a command signal to the mud pumps to stop the mudpumps, or a preselected subset of the mud pumps.
 9. The system of claim1, wherein the system is configured to monitor the fluid flow rate overa preset test period.
 10. The system of claim 1, wherein the system isconfigured for coupling to, to communicate with or may be operativelyassociated with a blow out preventer (BOP) of the installation, theinitial well control protocol comprising a command signal to the BOP toclose the BOP.
 11. The system of claim 1, wherein the system isconfigured to action a further well control protocol.
 12. The system ofclaim 11, wherein the further well control protocol comprises or takesthe form of an influx circulation operation.
 13. The system of claim 11,wherein the further well control protocol comprises or takes the form ofa well kill operation.
 14. The system of claim 11, wherein the furtherwell control protocol comprises or takes the form of a fluid pumpingoperation.
 15. The system of claim 1, wherein the system comprises, iscoupled to or may communicate with, a sensor arrangement for detectingthe fluid flow rate or fluid volumetric rate from the wellbore.
 16. Thesystem of claim 1, wherein the sensor arrangement further comprises atleast one of: a sensor configured to measure fluid volumetricdisplacement; a pressure sensor; a depth sensor configured to measurethe rate of penetration of the drillstring; a weight sensor configuredto measure weight of the drillstring; a gas detection sensor configuredto detect the presence and/or percentage of gas in the drilling fluid;one or more sensors configured to measure drilling fluid weight, yieldpoint and/or plastic viscosity; a speed sensor configured to measureequipment speed; a condition sensor configured to measure equipmentcondition; a movement sensor configured to measure heave, sway, surge,roll, pitch and yaw of the installation; and a wind speed and/ordirection sensor configured to wind speed and/or direction.
 17. Thesystem of claim 1, wherein the system comprises, is coupled to, oroperatively associated with a human machine interface (HMI) arrangement.18. The system of claim 1, comprising a communication arrangementconfigured to communicate said command signal to the well controlinfrastructure.
 19. The system of claim 1, wherein the system comprises,is configured for connection to or is operatively associated with amanaged pressure drilling system of the installation.
 20. The system ofclaim 1, wherein at least one of: the system comprises an early kickdetection system; the system is configured for connection to and/oroperatively associated with an early kick detection system of theinstallation.
 21. An offshore or onshore oil and/or gas installationcomprising the automated system for use in well control of claim
 1. 22.An automated method for use in well control, the method comprising:receiving a signal indicative of a fluid flow rate or fluid volumetricrate from a wellbore; determining from said signal whether the fluidflow rate or fluid volumetric rate exceeds a preselected threshold,wherein, on determining that said received fluid flow rate or fluidvolumetric rate exceeds said preselected threshold, the method comprisesautomatically initiating an initial well control operation.
 23. Themethod of claim 22, wherein the controller additionally receives one ormore input signal in the form of: fluid volume data; fluid volumetricdisplacement data; pressure data; depth data; drillstring weight data;gas detection data; data indicative of the gas percentage in thedrilling fluid; drilling fluid property data; equipment speed data;equipment condition data; movement data regarding the installation;environmental data; tidal data; GPS and/or other positioning systemdata.
 24. The method of claim 23, wherein the controller additionallyreceives one or more input signal in the form of managed pressuredrilling (MPD) system data and/or early kick detection system (EKDS)data.
 25. The method of claim 23, wherein the controller may beconfigured to receive one or more input signal in the form of a manualconfirmation input, e.g. from the operative.
 26. The method of claim 23,wherein the controller is configured to receive one or more input signalin the form of well control procedure data and/or leak-off test data.27. A processing system configured to implement the method of claim 22.28. A computer program product configured such that when processed by asuitable processing system configures the processing system to implementthe method of claim
 22. 29. A carrier medium, the carrier mediumcomprising a signal, the signal when processed by a suitable processingsystem causes the processing system to implement the method of claim 22.